Presented By:
Drew Welton
intellirent, division of ElectroRent Corp.
TechCon 2023
Abstract
Excessive moisture within the oil and insulating materials of a transformer has a significant effect on the life cycle of these critical and expensive assets. Moisture is one of the most influential elements that can accelerate aging in oil, paper, and pressboard insulation, possibly resulting in severe damage and premature failure. We’ll discuss how moisture accumulates, how it affects the aging process, and how significant damage or failure from excessive moisture can occur. We will look at ways to determine the amount of moisture that is present, and what drying options can be applied to eliminate moisture, potentially extending the life of the transformer. We will discuss the challenges associated with using traditional dissolved gas analysis, (DGA), or oils screens for moisture determination, and explore more modern techniques such as dynamic frequency response, (DFR). Included are specific case studies that will support the findings and recommendations.
I. DAMAGING EFFECTS OF EXCESSIVE MOISTURE
It is worth mentioning the dangerous effects of moisture and high temperatures in insulation systems. Together they negatively affect the performance and life expectancy of insulation systems. Moisture and/or high temperatures contribute to the following:
- Decrease in dielectric withstand
- Accelerated cellulose aging
- Bubble evolution
Moisture enables acids to serve as a catalyst to assist the breakdown process of the insulation. As the polymer chains of the cellulose are broken down into smaller chains, the cellulose over time becomes brittle. This brittleness can be measured by the Degree of Polymerization (DP), where new cellulose has a DP of 1200 and a DP of 200 indicates “end-of-life”.
Moisture lowers the bubbling point in the transformer. This creates voids in the insulation and can result in a partial discharge (PD). PD can lead to excessive deterioration of the insulating paper which can become irreversible. (fig.1)
In Fig.2 we compare operating temperature, along with moisture content, and how it corresponds to life expectancy. Overheating can be the result of overloading, poor cooling systems, or abnormal operating conditions such as excessive volts per hertz.
II. Causes of Excessive Moisture
Excessive moisture in a transformer’s insulting system can be summarized as follows:
A. External Moisture Ingress
Moisture intrusion from outside humid air makes its way into the transformer by:
- Leaking seals or gaskets surrounding the bushings or radiator
- Free-breathing conservator without a descant, or improper descant
- During bushing changes or installations
- During the manufacturing process
B. Natural Aging of the Insulating Materials
- Degeneration of the cellulose material and paper within a transformer ultimately determines its service life
- The measure of cellulose health is referred to as the “Degree of Polymerization” (DP)
- As the cellulose ages, resin bonds break down into smaller lengths, and the DP values fall
- The breakdown of the resin bonds produces CO, CO2, and H20
- The water molecules greatly reduce the mechanical forces the insulating system can withstand.
C. Moisture Assessment Samples
- As an industry standard, IEEE C57.106-2002 states that for new transformers moisture content should not exceed:
- 500 kV- Less than .05% by weight
- 69-240 KV- Less than 0.8% by weight
- 230 kV and below- 1.25% by weight as an example:
- A new 450 MVA, 245-20 kV two-winding transformer weighs ~ 250T
- Core & coils 125T of which 25T is cellulose
- At 2% water, there is 500 kg (132 US Gallons!) of water in the insulation.
- To achieve recommended 0.5% moisture content, 375 kg (99 US Gallons!) of water must be removed prior to installation.
The typical increase of moisture in a transformer can be in the order of 0.05 to 0.2%/year depending on the design. Figure 3 classifies the degree of moisture content and the scale of criticality based on various industry standards.
III. Moisture Measurement Methods
A. Direct Method; Karl Fischer Titration
Taking a paper sample from the transformer’s insulation for laboratory analysis. However, several factors may affect the results of KFT analyses:
- There can be an 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.
- Another issue for direct measurements of moisture in cellulose is the uneven distribution of moisture within the transformer.
KFT results also suffer from a poor comparability between different laboratories
B. Indirect Methods; 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 can be 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.
C. Relative Humidity
Transformer monitoring systems now incorporate capacitive probes that can determine the amount of moisture present in the oil. Since this is an online test, an equilibrium assessment to determine moisture content in the insulation has better reliability in applying temperature correction. Figure 4 shows an example of a modern capacitive probe.
D. Polarization/Depolarization Current (PDC)
A time domain current measurement records the charging and discharging currents of the insulation. They are usually called Polarization and Depolarization Currents PDC. Figure 5 illustrates the test current response of a PDC measurement.
E. Power Factor Frequency / Tan Delta Measurements
Traditional 50/60Hz Tan Delta, or Power Factor measurements indicate the overall health of the transformer’s insulation system. Insulation systems consisting of cellulose and oil exhibit both polarization and conductivity phenomena.
These two phenomena occur simultaneously, and superposition must be applied to separate the effects of both cellulose and oil. Moisture, temperature, and aging by-products influence both polarization and conductivity domains, where moisture has the greatest influence. Both polarization and conductivity effects can be represented by the losses they create.
Plotting dissipation factor as a function frequency provides insight regarding the characteristics of moisture, aging, temperature, contamination, oil conductivity, and the influence of external environmental conditions.
- Polarization Losses
In the frequency range in the neighborhood of DC (0 Hz) to 10 kHz, two types of polarization losses exist, interfacial polarization (0.3 – 0.5 mHz.) and molecular polarization (10 kHz).
When combining insulating materials within an insulation system, such as cellulose paper and mineral oil are combined, an interfacial polarization zone can be defined. Interfacial polarization is typical for non-homogeneous dielectrics with different permittivity or conductivity. The result will be the accumulation space charge carriers at the oil/paper interface. The interfacial polarization is the resonance that occurs between the propagation speed and distance traveled of the space charge carriers as a function of the insulation geometry (ratio between oil, barriers, and spacers). Depending on the moisture content and conductivity of the cellulose and oil, respectively, interfacial charge resonance occurs at different frequencies, e.g., 1 mHz. for dry and cool insulation systems, and >1 Hz for wet and hot insulation systems.
In cellulose and oil insulation systems the individual molecular structures produce polarization losses. These losses can peak around 10 kHz. At or near 60 Hz, these losses cause the power factor values to slightly increase and decrease proportionally with frequency for healthy insulation systems. Figure 6 illustrates this behavior in the 10 Hz to 1 kHz range.
- Conductive Losses
Both cellulose and oil exhibit conductive losses, however, oil is unique in the fact that by itself it solely produces conductive losses. Figure 6 illustrates contact conductive losses in oil. While conductive losses are seen in both cellulose and oil, the losses in the oil dominate. At very low frequencies occurring below the interfacial polarization range, the opposite is true, the conductive properties of oil are minimized as compared to cellulose.
A. Dielectric Frequency Response (DFR)
The Dielectric Frequency Response test measures and models the properties of insulation systems across a wide frequency range, e.g., 0.1 mHz. to 1000 Hz. This frequency range spans over 7 decibels enabling separation between the effects of polarization losses, conductive losses, and aging by-products within the overall insulation system. Modeling algorithms are applied to estimate moisture, conductivity, and insulation geometry.
Figure 8 displays the dielectric behavior of solid insulation and oil having 1.0 % moisture content at 20°C. The frequency range of 10 Hz – 1 kHz is dominated by the cellulose insulation, however, the measurement cables and the connection technique also influence this region. Oil conductivity causes the steep slope at 0.01 Hz – 1 Hz. Conductive aging by-products increase the oil conductivity and thus influence this area. The interfacial polarization (insulation geometry, duct space characteristics, ratio between oil, barriers, and spacers) determines the “hump” in the very low frequency range. The higher the ratio of oil to pressboard in the duct space, the more dominating is this effect. Finally, the moisture effects within the cellulose appear again at the frequencies below 0.5 mHz.
IV. Drying Methods
Two major techniques are used:
- Drying the insulation by drying the oil
This method can be performed with molecular sieves, cellulose filters, cold traps, combined oil regeneration and degassing. Considerations for these methods should include keeping the transformer in service during the drying process, cost of the drying process, and size of the transformer. Newer technologies in high-volume filtration systems offer a cost-effective solution, along with the ability to remove combustible gasses during the filtration process.
Modern online drying systems utilize large-capacity absorbent filters that store the water during the filtering. At regular intervals the filters are automatically regenerated (re-dried). Regeneration of the filters at regular intervals considerably increases water removal efficiency and accelerates the water removal process from the transformer. One benefit of using this method over alternative continuous high vacuum systems is that it does not remove the nitrogen blanket from the transformer, disturb the oil dissolved gas analysis, or alter the oils chemical qualities. These systems also allow for remote monitoring via cellular modem.
- Case study using a modern, high-capacity online drying system:
A portable online drying system (fig.8) was used on a group of near identical, 3 ph. – 66/22 Kv,10 Mva transmission transformers over 40 years old with 12,000 liters of oil and free breathing.
The pre-filtering water in cellulose was calculated at 4.44% at midday, and as the transformer increased in load/temperature, the 5pm calculation was 4.32%. This is a normal event.
When the transformer was re-analyzed after 72 days of drying, the 12:00pm water in cellulose calculation was 2.91% and the 5pm 2.64%. Most importantly, the oil relative saturation has reduced by 13% at the same load point, and the dielectric is markedly improved. This process was conducted without the need of taking the transformer offline.
An additional drying cycle of 2 weeks eventually reduced the moisture content down to just under 2%.
- Drying the insulation with heat and vacuum
A popular method for drying the insulation of a new transformer is through vapor phase drying, performed in a manufacturing setting. This process does not lend itself well to transformer drying in the field for a variety of reasons, including the difficulty of removing residual kerosene which can cause a potential change in the transformer oil flash point. Vapor phase drying methods can also create further breakdown of the cellulose within an aged asset.
V. Conclusion
Moisture is one of the worst enemies of a power transformer. It limits its loading capability, accelerates its aging 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 effectively be performed with modern filtration techniques without taking the transformer offline.
References
[1] Sample Reference Section: IEEE C57.161-2018, “IEEE Guide for Dielectric Frequency Response Test”.
[2] M. Koch, M. Krüger: “Moisture Determination by Improved On-Site Diagnostics”, TechCon Asia Pacific, Sydney 2008
[3] S.M. Gubanski, P. Boss, G. Csepes, V. Der Houhanessian, J. Filippini, P. Guuinic, U. Gafvert, V. Karius, J. Lapworth, G. Urbani, P. Werelius, W. Zaengl. “Dielectric Response Methods for Diagnostic of Power Transformers” Report of the TF D1.01.09, CIGRE 2002
