Estimating moisture in power transformers



 

Modern technology and developments in signal acquisition and analysis techniques have provided new tools for transformer diagnostics. Of particular interest are dielectric response measurements where insulation properties of oil-paper systems can be investigated.

Dielectric frequency response, (DFR, also known as Frequency Domain Spectroscopy, FDS), was introduced more than 15 years ago and has been thoroughly evaluated in a number of research projects and field tests with good results.

DFR data in combination with mathematical modeling of the oil-paper insulation is proven as an excellent tool for moisture assessment. The dryness of the oil-paper insulation systems in power transformers is a key factor in both their short and long term reliability since moisture has harmful effects on dielectric integrity and increases insulation ageing rates.

The condition of the insulation is an essential aspect for the operational reliability of electrical power transformers, generators, cables and other high voltage equipment. Transformers with high moisture content have a higher ageing rate and cannot sustain increasing loads.

On the other hand it is important to identify “good” units in the ageing population of equipment. Adding just a few operating years to the expected end-of-life for a transformer means substantial cost savings for the power company.

Fig. 1: Life expectancy for cellulose at different temperature
and moisture content [3].

Moisture in transformers

The insulation system of power transformers consists of oil and cellulose. Both materials generally change their dielectric properties during the life of the transformer and among factors contributing mostly to the degradation of transformer insulation, moisture plays an important role. Presence of water in solid parts of the insulation, even in small concentrations, increases its ageing rate, lowers the admissible hot-spot temperature and increases the risk of bubble formation. In addition, moisture reduces the dielectric strength of transformer oil as well as the inception level of partial discharge activity [1].

Where is the water?

When discussing moisture in transformers it is important to understand where the water resides. Consider the following example (typical values for a 300 MVA service aged power transformer at 50°C):

  • The insulation in a power transformer consists of oil impregnated cellulose and oil.
  • 60 t of oil with water content of 20 ppm = 1,2 ℓ
  • 10 t of cellulose with 3% water content = 300 ℓ
  • Almost all the water is in the cellulose.

During normal operation at different loads and temperatures, the water moves back and forth between oil and cellulose. Sometimes the water content in the oil is doubled, i.e. 40 ppm/2,4 ℓ. However the moisture in the cellulose remains almost the same: 299 ℓ. The average moisture content in the solid insulation is very constant.

Fig. 2: Recommended maximum loading limits as function of moisture [4].

Moisture accelerates ageing

Ageing of the cellulose insulation is directly related to the moisture content. Fig. 1 describes life expectancy for the insulation at various temperatures and moisture content [3]. At 90°C, cellulose with 1% moisture has a life expectancy of about 12 years. At 3% moisture the life expectancy is only 3 years.

Moisture limits the loading capability

A rise in temperature, especially at thick insulation layers, causes evaporation of adsorbed water with a high vapour and gas pressure within the inner layers of paper. This pressure may become high enough to create formation of vapour-filled cavities (bubbles) on the insulation surface with subsequent decrease of dielectric strength [2].

Where does the water come from?

Transformers are dried during the manufacturing process until measurements or standard practices would yield a moisture content in the cellulosic insulation of less than 1%. After the initial drying, the moisture content of the insulation system will continually increase. There are three sources of excessive water in transformer insulation [2]:

  • Residual moisture in the thick structural components which was not removed during the factory dry-out or moistening of the insulation surface during assembly.
  • Ingress from the atmosphere (breathing during load cycles, site erection and/or maintenance/repair processes).
  • Decomposition of cellulose and oil

Residual moisture

Excessive residual moisture can remain in some bulky insulating components, particularly in wood and plastic or resin-impregnated materials, which need much longer drying times than paper and pressboard. Typically, these are supports for leads, support structures in the load tap changer (LTC), support insulation for the neutral coils of the winding, cylinders, core support insulation, etc.

Fig. 3: Produced water as a function of number of chain scissions [2].

Different insulation materials require different drying durations. The drying time is roughly inversely proportional to insulation thickness in square. However the structure of material is an important factor as well, e.g. pressboard featuring a high density requires longer drying time than low density pressboard [2].

New transformers are generally dried to a moisture content <1%. When drying larger transformers, the residual moisture may be as low as about 0,3%.

Ingress from the atmosphere

The main source of the buildup of water in transformers is the atmosphere and there are several mechanisms and occasions for moisture ingress.

  • Exposure to humid air during site installation.
  • Leaking gaskets and faulty water traps may expose the inside of the transformer to humid air.
  • Exposure to humid air during maintenance.

Decomposition of cellulose

The ageing of cellulosic materials leads to molecular chain scission and the formation of byproducts including water and furanic compounds.

Fig. 3 describes several studies on how moisture is produced as a function of a number of chain scissions. After five chain scissions a paper starting at a degree of polymerisation of 1200 has ended up with a DP of 200 [2].

Typical increase of moisture in a transformer can be in the order of 0,05 to 0,2%/year depending on the design [2, 5].

Fig. 4: Moisture assessment examples.

Standards and recommendations for moisture

International standards and guides give some recommendations for moisture assessment. As an example IEEE C57.106-2002 recommends the following approximate percentages by weight of water in solid insulation:

  • <69 kV: 3% maximum
  • >69 to <230 kV: 2% maximum
  • 230 kV and above: 1,25% maximum

Other standards and guides only give a classification of the moisture content.

Moisture measurements

There are several methods available to measure the moisture content in the solid insulation of the transformer.

Direct method

• Take paper sample from transformer and measure moisture content using KFT.

Indirect methods

  • Moisture in oil
  • Absolute values
  • Relative saturation
  • Power frequency tan delta/power factor measurements
  • Dielectric response measurements
  • Return voltage measurement (RVM) – DC method.
  • Polarisation-depolarisation current measurements (PDC) – DC method.
  • Dielectric frequency response measurements (DFR/FDS) – AC method.

Fig. 5: Moisture content in paper in percentage relative to weight as measured by seven laboratories [1].

Direct method – KFT on paper samples

Karl Fischer titration allows for determining trace amounts of water in a sample using volumetric or coulometric titration. Its principle is to add a reagent (titre iodine) to a solution containing an unknown mass of water until all water reacts with the reagent. From the amount of reagent the mass of water can be calculated.

Several factors may affect the results of KFT analyses:

  • There is always ingress of moisture from the atmosphere during sampling, transportation and sample preparation. This happens particularly during paper sampling from open transformers.
  • Cellulose binds water with chemical bonds of different strengths. It is uncertain whether the thermal energy supplied releases all the water.
  • Heating temperature and time changes the released water.

To investigate the effect of these influences and to evaluate the discrepancies which may result from KFT analyses, a round robin test (RRT) was carried out among seven laboratories from four European countries [1]. It concentrated on analysing the water content in paper relative to weight and the water content in oil relative to weight in three oil and paper samples according to the respective laboratory’s standard procedures. The obtained results revealed an unsatisfactory comparability between the laboratories.

As seen in Fig. 5 the results show large variations. For sample A, containing little water, the comparability was worst. Moisture estimates varied between 1 and 2%.

Another issue for direct measurements of moisture in cellulose is the uneven distribution of moisture. In the “Rediatool” project [8], samples were taken from different parts of a transformer and analysed for moisture. Results are presented in Fig. 6. The moisture distribution is very uneven between different parts and locations. To get a true result from KFT analysis of paper it is important to take many samples and average the results.

Water content determination by means of dielectric response or other indirect methods is often calibrated by comparing them with evaluations based on KFT. However, KFT results also suffer from a poor comparability between different laboratories. The user must therefore be aware of this fact, and understand that a deviation in the comparison does not necessarily point out weaknesses of the evaluated methods.

Fig. 6: Moisture content estimated by means of KFT in samples of transformer solid insulation at different locations and sampling events [8].

Moisture in oil

Measuring moisture levels in oil is probably the most common method for moisture assessment. Many operators of power transformers apply equilibrium diagrams to derive the moisture by weight (%) in cellulose from the moisture by weight in oil (ppm). This approach consists of three steps:

  • Sampling of oil under service conditions
  • Measurement of water content by Karl Fischer titration
  • Deriving moisture content in paper via equilibrium charts

The procedure is affected by substantial errors, e.g:

  • Sampling, transportation to laboratory and moisture measurement via KFT causes unpredictable errors.
  • Equilibrium diagrams are only valid under equilibrium conditions (depending on temperature established after days/months).
  • A steep gradient in the low moisture region (dry insulations or low temperatures) complicates the reading.
  • The user obtains scattered results using different equilibrium charts.
  • Equilibrium depends on moisture adsorption capacity of solid insulation and oil.

For the drier samples A and B only a trend was recognisable; the results varied from 3,5 to 12,1 ppm for sample A and from 5,8 to 19,8 ppm for sample B. Systematic differences were obvious. It has to be mentioned that for the dry oils, the results also varied within one single laboratory and a standard deviation of 20% between laboratories is not unusual.

One step to improve the method of using equilibrium diagrams is to use the relative saturation in oil or water activity instead of the moisture by weight. Where direct measurements are performed with a probe mounted directly on the transformer, the issues with sampling and transportation are removed. Furthermore the moisture absorption capacity is less temperature dependent and oil ageing and its influence on moisture saturation becomes negligible, since it is already included in relative saturation [2].

Fig. 7: Moisture content in oil in ppm relative to weight as measured by the laboratories [1].

Power frequency tan delta/power factor measurements

Tan delta/power factor measured at power frequency (50 Hz) shows the combined dissipation factor coming from losses in oil and cellulose. It is known that this measurement cannot discriminate a dry transformer with service aged oil from a wet transformer with new oil and the method is relatively insensitive to moisture levels below 2%.

It is also well known that the standard tan delta temperature correction factors or tables (TCF) given in standards and in many instrument manufacturer’s user manuals/recommendations, are incorrect for the individual transformer [9]. This adds an additional source of inaccuracy to the method.

Dielectric response measurements

Dielectric response measurements can be performed in time (DC) or frequency (AC) domain. The most common measurement techniques/methods are:

DC methods – Time domain

  • Return voltage measurement (RVM); voltage vs. time
  • Polarisation-depolarisation current measurement (PDC); current vs. time

AC method – Frequency domain

  • Dielectric frequency response measurements (DFR/FDS); capacitance and dissipation factor vs. frequency.

Different methods have been thoroughly investigated in several tests and experiments [7]. The dielectric response methods RVM, PDC and DFR/FDS where used to analyse the moisture content for different arrangements of insulation geometry at different temperatures by the corresponding software programs. Results were compared to KFT analysis.

Fig. 8: Equilibrium chart for moisture content in paper versus water content in oil at various temperatures.

The results of RVM analysis differed strongly, although the moisture content of paper was constant during all the measurements. Dependences on the oil conductivity as well as on the temperature and the insulation geometry appeared. Hence the RVM software used could not evaluate moisture in oil-paper-insulation systems well since the interpretation scheme used was inaccurate without taking into account the geometry and oil parameters.

Results of PDC analysis showed much smaller influence of insulation geometry and weaker temperature dependence. These influences were already compensated for by the interpretation software used. With increasing oil conductivity, the evaluated moisture content increased, although in reality it remained constant. Nevertheless, the simulation results were close to the level evaluated by Karl Fischer titration.

The DFR/FDS analysis provided the best compensation for insulation geometry. At the same time, the paper seemed to become drier with increasing temperature. This actually happens in reality because of moisture diffusing out of the paper, but not to the indicated extent. The observed tendency rather reveals imperfect compensation for temperature variations. Similarly, an increased oil conductivity results in a slight increase in the estimated moisture content.

Dielectric frequency response measurements

The first field instrument for DFR/FDS measurements of transformers, bushings and cables was introduced 1995 [9]. Since then numerous evaluations of the technology have been performed and several international projects/reports define dielectric response measurements together with insulation modeling as the preferred method for measuring moisture content of the cellulose insulation in power transformers [1, 6, 7].

Fig. 9: DFR/FDS test setup.

In DFR tests, capacitance and dissipation/power factor is measured. The measurement principle and setup is very similar to traditional 50 Hz testing, but with a lower measurement voltage (200 V) and instead of measuring at line frequency (50 Hz), insulation properties are measured over a frequency range, typically from 1 kHz down to 1 mHz.

The results are presented as capacitance and tan delta/power factor vs. frequency.

Moisture assessment

The method of using DFR for determining moisture content in the oil-paper insulation inside an oil-immersed power transformer has been described in detail in several papers and articles elsewhere [1, 6, 7, 10] and is only briefly summarised here.

The dissipation factor for an oil/cellulose insulation plotted against frequency shows a typical inverted S-shaped curve. With increasing temperature the curve shifts towards higher frequencies. Moisture influences mainly the low and the high frequency areas. The middle section of the curve with the steep gradient reflects oil conductivity.

Fig. 10: Drying velocity from 3% down to 1,5 % average humidity.

Using DFR for moisture determination is based on a comparison of the transformer’s dielectric response to a modelled dielectric response (reference curve). A matching algorithm synthesises a modelled dielectric response and delivers a reference curve which reflects the measured transformer. Results are displayed as moisture content along with the temperature corrected power frequency tan delta and oil conductivity. Only the insulation temperature (top oil temperature and/or winding temperature) needs to be entered as a fixed parameter.

Comparing DC and AC techniques/methods

DC and AC measurements can be performed at low or high voltages and it is also possible to combine techniques by mathematically converting time domain data to frequency domain data and vice versa [11]. When selecting a suitable method for field measurements it is important to consider how sensitive the instrument is to substation interference.

A summary is presented in Table 1. AC methods are generally more robust in high-interference conditions. DC methods, particularly low voltage DC measurements, are very sensitive to DC interference from corona. The interference will add to the measured polarisation current which the analysis will interpret as increased moisture in the insulation.

Transformer drying

Transformer drying is an important maintenance action in today’s ageing transformer fleet and several reports and publications describe the issues related to drying [11, 12, 13].

Table 1: Noise sensitivity for different dielectric response measurement methods.
DFR measurement technologies
Interference signals Low voltage DC Low voltage AC High voltage AC
AC (50 Hz +harmonics) Sensitive Not sensitive Not sensitive
DC/VLF Very sensitive Sensitive Not sensitive

The different methods for drying can be summarised as follows:

Two major techniques are used:

• Drying the insulation by drying the oil
• Drying the insulation with heat and vacuum

Drying the oil can be performed with:

• Molecular sieves
• Cellulose filters
• Cold traps
• Combined oil regeneration and degassing

Drying the insulation can be performed with:

• Vacuum and heat
• Pulsation drying through oil circulation
• Hot oil spray drying
• Low frequency heating
• Vapour phase drying

Fig. 11: Drying time to dry a 400 MVA transformer with 14 ton insulation from 3% down to 1,5 % average humidity [13].

All of these methods can remove water out of the transformer insulation. However the efficiencies in the different techniques vary to a very large extent. Figs. 10 and 11 describe water extraction capacity and the time needed to dry a 400 MVA transformer with 14 t insulation from 3% down to 1,5% moisture content.

Conclusion

Moisture is one of the worst enemies of a power transformer. It limits its loading capability, accelerates its ageing process and decreases its dielectric strength. The water/moisture in a transformer resides in the solid insulation, not in the oil. Dielectric frequency response measurement is a good technique for moisture assessment as it can measure moisture content in the cellulose insulation, the conductivity/dissipation factor of the insulating oil accurately (corrected to 25°C reference temperature), and the power frequency tan delta/power factor, accurately (temperature corrected to 20°C reference temperature). Drying a power transformer can take from days to years depending on the drying process and the technology employed.

References

[1] Cigré Technical Brochure 414: “Dielectric Response Diagnoses For Transformer Windings”, 2010.
[2] Cigré Technical Brochure 349: “Moisture Equilibrium and Moisture Migration within Transformer Insulation Systems”, 2008.
[3] EL Lundgaard, W Hansen, D Jinhjell, and JT Painter: `“Ageing of Oil-Impregnated Paper in Power Transformers”, IEEE, 2004.
[4] GK Frimpong, et al: “Estimation of Moisture in Cellulose and Oil Quality of Transformer Insulation using Dielectric Response Measurements”, Doble Client Conference, 2001.
[5] SM Gubanski, et al: “Dielectric Response Methods for Diagnostics of Power Transformers”, Cigré Electra, No. 202, June 2002.
[6] SM Gubanski et al: “Reliable Diagnostics of HV Transformer Insulation for Safety Assurance of Power Transmission System. REDIATOOL – a European Research Project”, Cigré 2006.
[7] IEEE C57.12.90-2006, IEEE Standard Test Code for Liquid-Immersed Distribution, Power, and Regulating Transformers.
[8] P Werelius, et al: “Diagnosis of Medium Voltage XLPE Cables by High Voltage Dielectric Spectroscopy”, 1998.
[9] U Gäfvert, et al: “Dielectric Spectroscopy in Time and Frequency Domain Applied to Diagnostics of Power Transformers”, 6th International Conference on Properties and Applications of Dielectric Materials, 2000.
[10] Mats Karlstrom, et al: “Dielectric Response Measurements in Frequency, Temperature and Time Domain”, TechCon, AsiaPacific, 2013.
[11] Andreas Gruber: “Online Treatment of Transformers and Regeneration of Insulating Oil”, TechCon, AsiaPacific, 2009.
[12] Georg Daemisch: “On line drying as indispensable part of Life time strength conservation of power transformers”, On-line drying panel session, Regensburg seminar.
[13] Paul Kostiner, et al: “Practical Experience with the Drying of Power Transformers in the Field Applying the LFH Technology”, Cigré 2004.
[14] “ABB Advanced Diagnostic Testing Services Provide Detailed Results”, 2006.
[15] BP Patel and DFR Holmgren: ”A Powerful Tool for Transformer Diagnostics”, TechCon, AsiaPacific, 2009.

Contact Ali Alanzoor, Megger, meenquiries@megger.com

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