Diagnostic Tests on HV Bushings BK Gupta RJ Densley

DIAGNOSTIC TESTS ON HIGH-VOLTAGE BUSHINGS

Abstract

B.K. Gupta R.J. Densley

Ontario Power Technologies 800 Kipling Ave, KR 15 1

Toronto, Ontario, Canada, M8Z 6C4

Oil-impregnated paper (OIP) is the primary insulation in equipment, such as transformers, switchgear, bushings, cables and their accessories, which are used in critical and non-critical circuits in electrical transmission and distribution systems. As a result of deregulation and increasing competition, increased loading of equipment is expected and this will lead to higher operating temperatures. In addition many components have been in service for more than thirty years and are approaching the end of their design life, usually thirty to forty years. To reduce costs utilities are moving to condition-based maintenance practices and away from regular maintenance practice. As a result diagnostic tests are required to accurately assess the condition of all components that use OIP insulation.

The paper describes the results of different diagnostic tools used to evaluate the condition of four bushings removed fiom the field and which have different degrees of aging. The measurement techniques investigated were capacitance, tan delta and loss current waveforms at 60 Hz, capacitance and tan delta at frequencies fiom 0.1 to 100 Hz, recovery voltage and partial discharge, both electrical and acoustical.

The results show that the techniques investigated were able to detect significant changes in aged bushings. Further work is recommended to relate changes in parameters such as loss current waveform, low frequency tan delta, recovery voltage, leakage current and partial discharges to the rate of aging

Introduction

Oil-impregnated paper (OIP) has good heat transfer properties, low dielectric loss and high breakdown strength, and, as a result, has been used as the primary insulation in electrical power equipment, such as transformers, switchgear, bushings, cables and their accessories, for about 100 years. This equipment represents a large capital investment for electrical utilities and also has to have high reliability to avoid lost revenues resulting fiom premature failure. Many pieces of equipment are over thirty years old and, as a result of deregulation of the power industry, may have to cany increased loads in the future. As a result electrical utilities are now being faced with decisions to maintain, repair, refurbish, or replace critical components. To further reduce costs, utilities are moving to condition-based maintenance practices and away fiom regular maintenance. Thus it is becoming increasingly important to determine the condition of OIP insulation by knowing:

How the insulation in the different components of the system age, i.e., aging factors, aging mechanisms and rate of aging

failure mechanisms under operating conditions the system operating conditions How to measure the aging by diagnostic tests

(-/ Criteria for repair, refbrbish or replace

The aging processes and failure mechanisms of OIP, particularly when used in transformers and cables, have received much attention and are reasonably well understood. However, there is limited information specific to bushings. The main aging factors of OIP are thermal, electrical, mechanical and environmental. The aging may be accelerated andlor localized due to the presence of contamination, e.g., water or particles, or defects inadvertently introduced during design, manufacturing, installation, etc.

Thermal aging can have a significant effect on OIP, particularly at temperatures above 120°C, and there have been several reviews of this complex subject [l - 41. The rate of degradation of OIP with temperature follows the well-known Arrhenius law. Thus the insulation life is given by:

Life cc 1/R a exp(E&T)

Where R is the chemical reaction rate, E, is the activation energy, k is the Boltzmann constant, and T is the absolute temperature. The degradation rate doubles for every 8 to 10 "C rise in temperature in the 80 to 110°C range. Since the thermal conditions are not uniform throughout the insulation premature aging at 'hot spots' occurs.

Aging of OIP is significantly increased when moisture is present; the equilibrium level in oil is some tens of ppm while the paper can absorb up to 5 to 8%. The rate of aging is accelerated by 6 to 16 times when the moisture content in the paper is increased fiom 0.3% to 2% [I]. Typically, for a dried system in a transformer, the moisture levels are 0.3 to 0.5% in the paper and about 10 ppm in the oil. The smaller volume of bushings allows them to be dried to lower moisture levels.

Electrical aging of OIP is due to partial discharges in gas bubbles formed by thermal degradation or by incomplete impregnation. The partial discharges will also generate gases, typically hydrogen, acetylene, ethane and methane. The amount of gas generated has been found to be directly proportional to the energy of the partial discharges [5] and ratios of different gases are determined to verify that the deterioration is due to partial discharges [6]. If the gas bubbles grow under the action of partial discharges, flashover can occur. In addition, partial discharges can cause carbonization of the insulation leading to conducting tracks which can eventually short out one or more of the metallic or nonmetallic conducting layers of a capacitance graded bushing. The partial discharges can be detected by electrical or acoustic techniques and increases in capacitance will reveal shorted conducting layers.

Polar byprducts, e.g., formed by partial discharges or water, produced by thermal aging or allowed to enter the apparatus through leaking seals, etc., will decrease the resistance and increase the dielectric constant of the insulation. This will result in a small increase in capacitance and a larger increase in the dielectric loss [7]. Other thermal degradation byproducts can also increase the conductivity of OIP [8]. Decreased resistivity and increased

C/ dielectric loss can produce thermal instability in the insulation leading to thermal runaway PI.

Bushings

In June 1995 CIGRE SC12 (Transformers) held a workshop on power transformer accessories, concentrating on bushings and on-load-tapchangers. A summary of the workshop was presented at the 1996 CIGRE [9]; the main points specific to bushings were:

the failure rate varied considerably in different countries ranging from about 5% up to 50% problems were reported with gaskets caused by overfilling the bushing with oil and also bad gaskets in relatively new bushings there was concern expressed about the thermal aging of the bushing oil with reports of sludge-like deposits at the oil-end of the porcelain which were correlated with a high failure rate oxygen and moisture ingress should be avoided to minimize thermal aging techniques to monitor the condition of bushings included capacitance, dielectric loss and recovery voltage measurements and dissolved gas analysis no service failures due to very fast transients were reported transformer manufacturers reported that failures of bushings had occurred after they had passed factory tests. It was suggested that the failures were caused by the formation of bubbles during the cooling of the transformer after the heat run

In a study of the thermal behavior of typical 69 kV OIP bushings, it was found that the thermal time constant was about one hour [lo]. The effects of conductor size, oil temperature, wind speed, etc. were determined in short term tests. In addition, life tests were carried out on one bushing by adjusting the load current to give a hot-spot rise in temperature of 120°C while maintaining the tank oil temperature at 88°C. Weekly load cycles were

(J carried out along with a 10 kV power factor measurement as a diagnostic test. After 23 weeks of aging, the power factor doubled and the test was terminated; the bushing was then subjected to capacitancelpower factor tests over a range of voltages, partial discharge tests and gas-in-oil analysis before disassembly to inspect the condition of the oil and the paper. There was a small increase in capacitance (3%), a doubling of the power factor, no partial discharges at the operating voltage, and significant increases in carbon monoxide and carbon dioxide with smaller increases in hydrocarbons except hydrogen and acetylene. All measured changes were consistent with thermal degradation of the oil and the paper. The oil had darkened and the power factor had increased from 0.002 to 0.003 for new oil to 0.1 35. The paper at the exterior of the core was unaffected and looked good for about 75% of the thickness of the core. The paper in the inner 25% of the core showed an increase in power factor and a 50% decrease in tensile strength. Although the gaskets showed some deformation, there were no leaks in the bushing after the aging test. In these aging tests no voltage was applied during the aging, thus eliminating the possibility of the occurrence of partial discharge degradation from gaseous bubbles formed during cooling.

Experimental

A series of diagnostic tests were carried out on four 1 15 kV bushings removed from the field. Two of the bushings were moderately aged and two were 'nearly new'. The following diagnostic tests were performed:

Capacitance and tan delta measurements at 60 Hz up to rated voltage

Dielectric spectroscopy (capacitance and tan delta at voltages from 200 V to 10 kV at frequencies between 0.1 and 100 Hz) Recovery voltage measurements Leakage current and partial discharge measurements, both acoustic and electrical, using monitoring equipment developed at OPT [I 11.

The tests were carried out at two temperatures, room temperature and also with 1200 A flowing through the bushings for at least twelve hours to achieve steady state conditions.

The recovery voltage tests were performed by applying 1,3 or 5 kV DC to a previously short- circuited bushing for a pre-determined time, usually 60 s, short circuiting the bushing for a known time, usually 10 s, and then measuring the open circuit voltage at the low voltage capacitive tap for up to 15 minutes. The bushing was short circuited for at least 5 minutes before testing.

The leakage current and partial discharge measurements were performed at the rated voltage of 66 kV. Current transformers connected between the low voltage capacitive tap and ground measured the leakage current and electrical partial discharges. An acoustic sensor located on the grounded metal case of a bushing measured the acoustic signals generated by the partial discharges.

Results

Capacitance and Tan Delta at 60 Hz

The capacitance and voltage of each bushing at 0 and 1200 A was measured at 60 Hz at L, , voltages up to 66 kV. At 1200 A, the temperature of the conductor just below the bottom of the bushing was - 70°C. The tan delta results for the four bushings are plotted in Figure 1. It

.) e! should be noted that the graphs do not have the same vertical scales. The tan delta of the unaged bushings (#3 and #4) remains uniform at 0.23 to 0.25% at all voltages and temperatures. However the tan delta increases by more than 100% at 66 kV at the higher temperature for the two aged bushings. The capacitance increased by -1% for all bushings at the higher temperature.

' ''1 r: ,&+" Figure 2a shows that the 180 and 300 Hz loss currents are significantly larger and increase

\ more rapidly with voltage for the aged bushings. There is also an order of magnitude increase in the 180 and 300 Hz loss currents of the aged bushings at the higher temperature, Figure 2b. The third and fifth harmonics for the two unaged bushings were less than the noise level (< 1mV) of the spectrum analyzer and could not be measured.

The 60 Hz high voltage capacitance and tan delta measurements show that significant increases in tan delta occur in aged bushings and that these increases are more pronounced at when the bushings are at high temperature. The loss current waveforms of aged bushings are distorted with measurable levels of 180 and 300 Hz components. The latter increase by about an order of magnitude at high temperature.

Capacitance and Tan Delta 0.1 Hz to 100 Hz

Both low-voltage (000V) and high-voltage (5 10 kV) measurements were performed with the WabTech bridge. The results of the high voltage tests at room and high temperatures for the aged bushing are shown in Figure 3 and those of the low voltage tests in Figure 4. The

corresponding results for the unaged bushing are shown in Figures 5 and 6 respectively. There is very little difference between the high and low voltage results, as can be seen when comparing Figures 3 and 4 or Figures 5 and 6. The dielectric constant of the aged bushmg increases at frequencies below 2 Hz probably due to increased polarization (also observed in the recovery voltage measurements described in the next section) whereas the unaged bushings maintained a uniform value over the whole frequency range (0.1 to 100 Hz). The tan delta of the aged bushings increases as the frequency decreases and reaches a plateau of about 60% below 1 to 2 Hz. Thus, below 1 to 2 Hz, the real and imaginary parts of the permittivity increase at the same rate. The tan delta values of the aged bushings at frequencies from 0.1 to 0.4 Hz are similar for both low and temperatures but are significantly larger at the elevated temperature for higher frequencies. The tan delta of the unaged bushings also increases slowly with decreasing frequency to about 3% at 0.1 Hz but does not reach a plateau. The values are more than an order of magnitude lower than those of the aged bushings.

The capacitance and tan delta, measured at low frequencies over the range of voltages examined in these tests (50 V to 10 kV), showed significant differences between aged and unaged bushings. Thus the technique is suitable as an off-line diagnostic tool to evaluate bushings.

Recovery Voltage Measurements

The peak voltage, time to reach the peak and the initial slope of the recovery voltage characteristics of the bushings are listed in Table 1. Typical results for an aged and unaged bushing, given in Figure 7, show that the voltage increases to a peak and then decreases more slowly. As the density of polar species is more numerous for aged insulation, there will be a larger polarization charge stored when the DC voltage is applied during the recovery voltage test. The aged insulation can be modelled as a geometric capacitance, a resistance in parallel to represent the conductivity of the insulation, and also in parallel, a number of capacitances, each with a resistance in series, to represent a polarization charge and its time constant. Thus the aged insulation will have a larger recovery voltage but shorter times to discharge as the conductivity will be greater. Unaged insulation will have less polarization and thus a lower peak recovery voltage but longer time constants.

As can be seen fiom Table 1, the recovery voltage usually increases less than linearly with charging voltage, except for bushing #2 at 0 A, which gave a linear response. The recovery voltage characteristics vary with temperature in a complex manner. For the two unaged and one of the aged bushings the peak voltage increased at the higher temperature. However for the bushing with the highest tan delta the peak voltage decreased. The time to peak voltage was consistently shorter at the higher temperature, probably due to the increased conductivity of the insulation.

The results show that aged bushing insulation has at least an order of magnitude larger peak recovery voltage and shorter times to reach the peak value than unaged insulation. The difference is greater at room temperature than at high temperature whereas the change in tan delta is larger at high temperature. Thus recovery voltage measurements may be a more suitable off-line test method. However more work is needed to clarify the effect of temperature.

Table 1: Results of Recovery Voltage Measurements at 0 and 1200A Bushing # V,/ t,/ So * 1 kV 3kV 5kV

? OA 1 1200 A 0 A 1 1200 A 0 A 1 1200 A

4 V m (V) 1.96 9.04 3.37 16.69 4.43 23.2 4 fm (s) 154 3 6 133 3 2 114 32 4 so (VM 0.078 0.654 0.1 1.41 0.15 1.87 * V, Peak Recovery Voltage, tm time to reach peak voltage, So initial slope

Leakage Current and Partial Discharge Measurements

The 60 Hz leakage currents measured at the capacitive taps of the four bushings were similar at both low and high temperatures. This was expected as the main component of the leakage current is the capacitive current which does not change appreciably with temperature. The L loss current, given by the tan delta measurements, contributes only about 1 % of the total leakage current. Significant changes in the leakage current would occur if any of the capacitive foils were shorted.

No partial discharges were detected on any of the bushings with either the electrical or acoustic PD detection techniques. When a sharp point was placed on the high voltage conductor, the electrical PD detection system easily detected corona at less than half the operating voltage.

Conclusions

Different diagnostic tools have been used to evaluate the condition of four 1 15 kV oil-paper bushings, two aged and two unaged. The following techniques show promise as off-line tools to detect aging:

Capacitance, tan delta and loss current waveform measurements at 60 Hz Capacitance and tan delta measurements at low frequencies (0.1 to 10 Hz) Recovery voltage measurements Leakage current and partial discharge measurements

The 60 Hz high voltage tan delta increased by up to an order of magnitude in the aged bushings; these increases were more pronounced at when the bushings were at high

L temperature. The loss current waveforms of aged bushings are distorted with measurable levels of 180 and 300 Hz components. The latter increase by about an order of magnitude at high temperature.

The tan delta, measured at low frequencies (0.1 Hz to 10 Hz) over the range of voltages examined in these tests (50 V to 10 kV), showed significant increases when the bushings are aged.

The results show that aged bushings have at least an order of magnitude larger peak recovery voltages and shorter times to reach the peak value than unaged bushings. The difference is greater at room temperature than at high temperature whereas the change in tan delta is larger at high temperature.

Partial discharges were not detected in these bushings. However it is an important diagnostic tool to measure electrical aging.

Although the techniques investigated can detect aging more work is needed to determine how changes in the parameters measured vary with the rate of aging. Such data may enable a prediction of the remaining life.

Acknowledgments

The authors would like to acknowledge the support of Mr. R. Glowacki for constructing the recovery voltage equipment, performing the tests and collecting the data. His efforts are greatly appreciated.

References

Fabre, J, and Pichon, A., 'Deteriorating Processes and Products of Paper in Oil. Application to Transformers', CIGRE Paper # 137, 1960, 1 8 pp. Shroff, D. H., and Stannett, A. W., 'A Review of Paper Aging in Power Transformers', IEE Proceedings, Vol. 132, Pt. C, November 1985, pp. 3 12 - 3 19. Emsley, A. M., and Stevens, G. C., 'Review of Chemical Indicators of Degradation of Cellulosic Electrical Paper Insulation in Oil-Filled Transformers', IEE Proc.-Sci. Meas. Technol., Vol. 141, September 1994, pp. 324 - 334. Gupta, B. K., McDemid, W., Polovic, G., Shenoy, V., and Trinh, G., 'Transformer Insulation Aging: A Review of the State of the Art', Canadian Electrical Association Task Force ST-393 Report, November 1994,lO pp. Viale, F., Poittevin, J., Fallou, B., Morel, J. F., Buccianti, R., Yakov, S., Cesari, S., and Serena, E., 'Study of a correlation Between Energy of Partial Discharges and Degradation of Paper-Oil Insulation', Paper 15-12, CIGRE, 1982,9 pp. IEC Publication No. 599, 'Interpretation of the Analysis of Gases in Transformers and other Oil-Filled Electrical Equipment in Service'. Batruni, R., Degeneff, R. C., and Lebow, M. A., 'Determining the Effect of Thermal Loading on the Remaining Life of a Power Transformer fiom its Impedance Versus Frequency Characteristic', IEEE Transactions on Power Delivery, Vol. 1 1, No. 3, 1996, pp. 1385 - 1390. McNutt, W. J., and Kaufmann, G. H., 'Evaluation of a Functional Life Test Model for Power Transformers', IEEE Transactions on Power Apparatus and Systems, Vol. PAS- 102, No. 5,1983, pp. 1151 - 1162. Goosen, P. V., 'Transformer Accessories', Paper 12 - 104, CIGRE 1996, 12 pp.

10. Craghead, D. O., and Easley, J. K., 'Thennal Test Performance of a Modern Apparatus Bushing', IEEE Trans. Power Apparatus and Systems, Vol. PAS-97, No. 6, 1978, pp. 2291 - 2299.

10. Schwabe, R. et al., 'An On-line Condition Monitoring System for High Voltage Current Transformers', Paper to be presented at this workshop.

Tan Delta Vs. Voltage, 0 A

Voltage (kV)

Tan Delta Vs. Voltage, 1200 A

40

Voltage (kV)

Figure 1: Tan Delta Vs Voltage at 0 and 1200 A Note that the scales of the vertical axes are different for the two graphs

(a) Third armonic of Loss Current Vs. Voltage, OA u

Voltage (kV)

(b) Third and Fifth Harmonics of Loss Current at 1200 A

40

Voltage (kv)

Figure 2: Harmonics of Loss Currents at 0 and 1200 A Note that the scales of the vertical axes are different for the two graphs

Figure 4: Variation in C and Tan Delta with Frequency for Aged Bushing (#2)-Low Voltage

Figure 5: Variation in C and Tan Delta with Frequency for Unaged Bushing (#3)-High Voltage

Figure 6: Variation in C and Tan Delta with Frequency for Unaged Bushing (#)-Low Voltage

Recovery Voltage: Bushing #2,O A, 5 kV

Time (Seconds)

Recovery Voltage: Bushing #4, 0 A, 5 kV

0 100 200 300 400 500 600 700

Time (Seconds)

Figure 7: Recovery Voltage Measurements for Bushings #2 and #4 at 5 kV, OA

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