PowerTest 2012
by Charles Sweetser, OMICRON electronics Corp. USA
Figure 1a: Losses in Cellulose Figure 1b: Losses in Oil Moisture and Temperature
It is worthy to mention 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. 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.”
MEASUREMENTS
Traditionally, basic measurements have been performed on insulation systems to estimate the condition or to identify an incipient failure mode. These methods range from oil and material analysis to Power Factor measurements.
Power Factor at Power Frequency
The Power Factor at one single frequency point has been used for decades to determine the integrity and condition of an insulation system. Figure 2 illustrates the equivalent circuit for losses in insulation materials and the corresponding vector diagram. Any solid or liquid insulation can be modeled by a capacitance Cp, representing the “ideal” behavior of insulation, and a resistor Rp, representing the electrical losses. The Power Factor (cos ) indicates the quality of insulation materials by the ratio of resistive current IR to total current IT [1].
Figure 2: Equivalent circuit for insulation materials and corresponding vector diagram
The first instrument to measure an unknown capacitance and its dissipation factor was the Schering Bridge. This is basically a four-arm alternating-current (AC) bridge circuit whose measurement depends on balancing the loads on its arms. The bridge required the use of a higher voltage, a few kV. For practical reasons, the frequency was mostly limited to power frequency. These historical conjunctures found its way into standards and field test practices, where a test voltage of typically 10 kV and a limited frequency range close to power frequency are used [1].
Industry standards give various limits for power factor. For example, IEEE Std. 62-1995 states that in the case of new oil-filled transformers and reactors, the power factor measurements should not exceed 0.50%. It further recommends that it is acceptable for older power transformers to have power factors between 0.50%
and 1.00%; however, power factors greater than 1.00% should be investigated.
Dielectric Frequency Response (DFR)
Dielectric diagnostic methods deduce moisture in paper or pressboard from dielectric properties like re-turn voltage, polarization and depolarization currents and dissipation factor.
Primary motivations for the development of dielectric response methods were the lack of methods for on-site moisture assessment in power transformers and the disappointing results of the hitherto used conventional equilibrium approach.
Recovery Voltage Method (RVM)
In this method, a voltmeter determines the recovery voltage after charging the insulation with a DC voltage. By subsequent relaxation and repeated charging for varied times the so called
“polarization spectrum” can be created [2]. This technique is outdated since its interpretation scheme appeared to be unable for compensating the interfacial polarization effect and oil properties [3]. In recent years, the Recovery Voltage Method has lost popularity to improved dielectric response methods, such Polarization and Depolarization Currents PDC [4] and the Frequency Domain Spectroscopy FDS [5].
Polarization and Depolarization Currents (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 3 depicts the shape and common interpretation of a PDC measurement.
Figure 3: PDC Wave Shape and Interpretation
Frequency Domain Spectroscopy FDS
The Frequency Domain Spectroscopy test measures and models the properties of insulation systems across a wide frequency range, e.g. 1000 Hz to 0.1 mHz. This frequency span over 7 decades enables for discrimination between the effects of polarization losses, conductive losses, and aging by-products within the overall insulation system [1]. Techniques that provide power factor measurements across a frequency band better help discriminate the characteristics of moisture, aging, temperature, contamination, oil conductivity, and the influence of external environmental conditions. Analysis algorithms are then applied to determine moisture, conductivity, and insulation geometry.
Figure 4 displays the dielectric behavior of paper, pressboard, 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 also the measurement cables and the connection technique influence this region. Oil conductivity causes the steep slope at 0.01 Hz – 1 Hz. Dissolved conductive aging by-products increase the oil conductivity and thus influence this area. The interfacial polarization (insulation geometry, ratio of oil to pressboard) determines the local maximum or “hump” in the 0.003 Hz range.
The higher the ratio of oil to pressboard, the more dominating is this effect. Finally, the moisture effects within the cellulose appear again at the frequencies below 0.5 mHz [1].
Figure 4: Dielectric Behavior for Cellulose and Oil as a Function of Frequency
Combining Time and Frequency Domain Measurements Combining the polarization current measurement method in time domain with the frequency domain spectroscopy can significantly reduce the testing time compared to existing techniques.
Essentially, time domain measurements can be accomplished in a short time but are limited to low frequencies. In contrast, frequency domain measurements are feasible for high frequencies but take a very long time to complete at low frequencies. Figure 5 illustrates
Figure 5: Combined PDC and FDS Measurement Using Transformation
the combining of time and frequency domain measurements. A transformation is applied to the time domain measurement and the final result is plotted as a function of frequency.
Power Factor Tip-Up
The Power Factor Tip-Up method monitors the behavior of insulation as a function of test voltage. The test voltage is generally increased at predetermined levels and the power factor is recorded. Healthy insulation systems in transformers and bushings should not produce the “Tip-Up effect”, whereby the percent power factor increases with an increase in voltage.
Sensitivity to Tip-Up can be caused by aging, localized defects that result in partial discharges, and defective connections in series with a given insulation path.
For practical purposes the “value” of Tip-Up is the difference between the 10 kV Power Factor and the 2 kV Power Factor for insulation systems rated at 15 kV and above. It is not the terminal voltage level that causes Tip-Up, but the localized field strength within insulation systems. The field distribution is dependent on the physical geometry of the test specimen. The electric field stress across a narrow gap in the insulation will be much higher than that across larger gaps. The gap size observation indicates that Tip-Up is a stronger diagnostic for bushing insulation systems as compared to large power transformers.
Figure 6a shows Tip-Up tests on 2 similar bushings. These are 500 kV 1975 Westinghouse Type O bushings. Figure 6b is a follow-up frequency sweep test that was also used to rule out moisture.
Figure 6a: Power Factor Tip-Up
Figure 6b: Variable Frequency Power Factor
The Tip-Up measurement in red is voltage sensitive, and the measurement begins to noticeably Tip-Up at 6 kV.
The way transformer insulation is tested greatly depends on application purpose, design and configuration. Various transformer test protocols exist. Table 1, shown below, lists a few common types.
Table 1: Main Insulation Components
With regards to moisture, the diagnostics should focus on the winding insulation (CHL, CHT, CLT, and CAutoT). The inter-winding insulation isolates the bulk cellulose. The bulk cellulose is influenced by both conductive and polarization losses near 60 Hz; however this measurement is very sensitive to the conductive losses in this range due to the conductivity of the oil. Figure 7 illustrates the superposition effects of the oil and cellulose. Figure 8 shows the conductive influence of the oil in the 60 Hz range.
Figure 7: Superposition of Cellulose and Oil
Figure 8: Polarization and Conductive Losses Near 60 Hz
Figure 9 illustrates typical 2-winding transformer measurements, which include CH, CL, CHL.
Figure 9: Typical 2-Winding Transformer Measurements (CH, CL, CHL)
Figure 10 shows inter-winding measurements from 4 different transformers with various levels of moisture present. The 60 Hz power factor measurements were 0.23%, 0.46%, 0.68%, and 2.16% at 20°C, see Table 2. The Extreme and Wet units measured 3.7 % and 4.6% moisture content by weight, respectively.
Figure 10: Inter-winding Measurements with Various Levels of Moisture Present
Table 2: Power Factor and Moisture Measurements
Figure 11, shown below, illustrates the CHL power factor behavior from two similar transformers. The 60 Hz power factors are identical (0.22%); however the overall responses are different.
These results would be an indication that T2 has a slightly higher moisture content.
Figure 11: Typical 2-Winding Transformer Measurements from similar transformers at 20°C.
CONCLUSION
Advanced diagnostic methods for analyzing moisture and the dielectric properties of power transformers and bushings are useful and pertinent tools with which to determine the insulation health of the subject apparatus. As an asset manager reviewing the life expectancy of the equipment or a power system operations manager responsible for determining the loading capabilities of the equipment, it is important to know the conditions and degree of moisture in transformers and bushings. In summary, the following points can be concluded from this paper:
1. Dielectric diagnostic methods deduce moisture in the solid insulation from dielectric properties like polarization and depolarization currents and dissipation factor vs. frequency [6].
2. Oil conductivity has a significant impact on the dielectric response of transformers, and therefore this must be compensated for when attempting to determine the moisture content of the solid insulation.
3. When performing a measurement at an arbitrary frequency (60Hz) it is not possible to separate the resistive (conduction losses) and the dielectric (polarization) losses [7].
4. Moisture predominately resides in the paper insulation, in lieu of the oil.
5. The Dielectric Frequency Response method provides a comprehensive approach to determining the moisture content in the solid insulation.
REFERENCES
[1] M. Koch, M. Krueger, M. Puetter. “Advanced Insulation Diagnostic by Dielectric Spectroscopy.” TechCon Asia–Pacific, Sydney 2009;
[2] E. Nemeth. “Measuring the Voltage Response, a Diagnostic Test Method of Insulation.” Proceedings of the VII International Symposium on High Voltage Engineering, ISH, Dresden, 1991;
[3] M. Koch, M. Kruger, S. Tenbohlen. “Comparing Various Moisture Determination Methods for Power Transformers.” South Africa Regional Conference, CIGRE 2009;
[4] V.D. Houhanessian. “Measurement and Analysis of Dielectric Response in Oil-Paper Insulation Systems.” Ph.D. Dissertation, Swiss Federal Institute of Technology Zurich, ETHZ, 1998;
[5] R. Niemanis, T.K. Saha, R. Eriksson. “Determination of Moisture Content in Mass Impregnated Cable Insulation Using Low Frequency Dielectric Spectroscopy.” IEEE Power Engineering Society Summer Meetings, p 463-468, vol. 1, Seattle, USA, July 16-20, 2000;
[6] M. Koch, M. Krüger. “Moisture Determination by Improved On-Site Diagnostics.” TechCon Asia Pacific, Sydney 2008;
[7] 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.” Preport of the TF D1.01.09 , CIGRE 2002.
It is common knowledge that transformer cost comprises any-where from 40-60% of the price of a substation. The cost has spi-raled out of control, up 40% from last year. These price increases have dried up the inventory of the used market and new transform-ers are averaging 50-56 weeks from order to arrival. All rewind shops are swamped and their time lines are growing as well. Un-fortunately, the majority of the U.S. transformer population is also at the end of the baby boom era and requires special care and test-ing if they are to continue to serve until the market can catch up. In some of the more progressive industries and utilities, transformer testing is nothing more than a walk around to look for leaks, nitro-gen and oil levels, LTC count, and the temperature recorded by the hot spot and top oil gages. Some company maintenance and test personnel have implemented DGA testing but many still have no clue of its value.
The companies that do regularly test transformers are many times still guilty of only testing what is inside the tank and totally overlook many of the obvious other transformer failure producing indicators on the outside. To truly test a transformer 100%, all of
the failure modes must be known and tested for on a regular basis.
All failure modes can be classified into one of the three follow-ing categories: mechanical, electrical and dielectric. Each of these categories should be further divided into internal and external test-ing. The last two divisions are what separate mediocre from the complete testing programs.
EXTERNAL FAILURE MODES
Mechanical failures are typically broken into LTC drive systems and cooling.
It is imperative the LTC make a full tap change at a speed where internal arcing damage is minimized. Items such as weak motor starting capacitors (Pictures 1 and 2) and low source voltage will cause the motor to labor; pull abnormally high currents, and even-tually burn up if not protected by a safety of some sort. Motor voltage should not drop more than 10% during tap change from 1 L to 1 R. Low voltage means high current and overheating. Bad source wiring or corroded connections to the LTC can also be a culprit of low voltage.