Abstract- In Mexico since 1995, polymeric insulators have been used in transmission lines exposed to severe contamination. Insulators from different manufacturers have been installed; however, some of them have failed during their early operation years. Consequently, since 2003, in-service diagnostic has been periodically carried out to identify high risk insulators, by using the visual corona and electric field measurement techniques.
In this paper, the most important results obtained from different inspections performed in-service to polymeric insulators on Mexican transmission lines are presented. These results show that the visual corona and electric field measurement techniques can be used to identify high risk polymeric insulators prior to failure.
I. INTRODUCTION
Since1995, polymeric insulators started to be used on the Mexican transmission lines which are exposed to severe contamination. The first experience was on a 230 kV transmission line where its ceramic insulators were washed twice a month for avoiding pollution outages [1]. After replacing porcelain insulator strings by polymeric insulators in different points along the transmission line, washing maintenance works have not been necessary. However, two years later, some polymeric insulators failed by tracking damage on their surface, and then these insulators were substituted by new ones.
Such occurred failures showed that, although the polymeric insulators have better performance than the traditional insulators under polluted conditions, their expected life and long term reliability is not yet known. Hence, from these failures, periodic inspections have been performed to identify high risk polymeric insulators.
During the following years, polymeric insulators have been installed on other transmission lines located on severe contamination zones along MÈxico, according to the results obtained from the first experience in the use of polymeric insulators in 1995. In each case, the inspections have been carried out since the beginning of the installation of these insulators.
The first inspections were performed by periodically observing at night from the ground the presence or the absence of surface discharges on the insulators. When high visual discharge activity was observed, it was determined if a failure could occur on the insulator. However, from this way, it could not be known if the surface discharges caused damage on the
insulator, therefore, the insulator long term performance was not possible. Furthermore, the failure determination mainly was depending on the experience of the worker who reviewed
the insulators.
Later, the leakage current technique was used for monitoring the performance of a few polymeric insulators, which were exposed to the highest pollution effects [2]. By means of this
technique, high risky insulators were detected when their peak leakage current values were very high. The insulators removed from service in order to visually revise them. The inspection showed strong erosion and tracking degradation along their surface. From this way, such technique could be considered to evaluate the performance of polymeric insulators as they are aged. Nevertheless, it is not economically feasible to install at least one leakage current sensor on each tower with polymeric insulation. Therefore, other line diagnostic techniques were reviewed [3].
II. METHODOLY USED TO INSPECT POLYMERIC
INSULATORS
For monitoring the operative condition of the polymeric insulators installed on 230 kV and 400 kV transmission lines, located in severe contamination areas, the visual corona and electric field techniques have been applied since 2003.
First, the insulators of the transmission line are inspected by the visual corona technique. Second, the electric field technique is applied to insulators on which corona activity is detected. Finally, the data obtained from the inspection are analyzed to determine the operative condition of the insulator [4-6].
The equipments used to apply these diagnostic techniques for polymeric insulators are: DayCor II corona camera,
In-Service Diagnostic of Polymeric Insulators Exposed to Severe Contamination
Ramiro Hern·ndez-Corona Gerardo Montoya-Tena Instituto de Investigaciones ElÈctricas (IIE) Reforma 113, Col Palmira Cuernavaca, Morelos, MÈxico 62490
2007 Annual Report Conference on Electrical Insulation and Dielectric Phenomena
1-4244-1482-2/07/$25.00 ©2007 IEEE 376
Authorized licensed use limited to: Tarbiat Modares University. Downloaded on September 26, 2009 at 07:59 from IEEE Xplore. Restrictions apply. developed by EPRI solutions, to detect visual corona, and the composite insulator tester, developed by Hydro-Quebec, to measure the electric field along the polymeric insulator.
The DayCor II camera can determine the position, type and count of the corona activity [7]. Furthermore, it is capable of detecting corona activity in daylight from the ground, from the
tower or from a helicopter. The information obtained can be recorded into a video camera and, later, can be analyzed to identify whether or not one insulator is defective.
The composite insulator tester measures the electric field along the polymeric insulators [8]. The measured data are stored in the memory of the tester. When the measurements are
finished, the data must be transferred into a computer. On the computer screen, the field curve as a function of the length of the insulators is displayed. According to the shape of the curve may be determined whether or not the insulator is damaged, since a defect in the insulator will change the electric field in a way more or less abruptly. In this case, the electric field measurements must be carried out from the tower. It is because the field probe is mounted on a carriage which must be slid by a lineman along the entire insulator.
III. DIAGNOSTIC OF POLYMERIC INSULATORS IN
SERVICE
At present, the polymeric insulators working on 230 kV and 400 kV transmission lines exposed to the high pollution have been inspected by both techniques mentioned above. These insulators are located in the Mexican states of Michoac·n, Veracruz, Tamaulipas, Baja California, Nuevo LeÛn, San Luis PotosÌ, Aguascalientes and Colima.
In the state of Michoac·n, the corona and electrical field distribution measurements have allowed detecting insulators with strong degradation on their surface. In the other states,
the obtained measurements show that the insulators do not represent risk for the operation of the transmission lines.
The degraded insulators in Michoac·n were detected on a 230 kV transmission line. The line is located in the Pacific coast in an industrial area whose main pollutants are iron particles from an iron and steel industry, chemical compounds from fertilizer industry, salt from sea, carbon and sand particles, which are deposited by the wind on the insulator surface.
In order to avoid outages caused by pollution, polymeric insulators from different manufacturers have been installed on the line since 1995. Some of them have early failed, but others
are still operating well on the line.
Since 2003, these insulators have been inspected by the visual corona and electric field techniques, in order to know if both techniques can be used to identify high risky polymeric
insulators prior to failure. The inspections have been performed 3 times: 2003, 2004 and 2006.
A. 2003 inspection
The most interesting results were obtained on the insulators installed in the towers 62-C, 62-B, 64-F and 64-V, which are into the more critical pollution zone. The main characteristics
of these insulators are showed in Table I.
TABLE I
MAIN CHARACTERISTICS OF POLYMERIC INSULATORS INSPECTED IN A 230 KV
TRANSMISSION LINE
Tower
Manufac-ture
housing
material
Length
(mm)
Leakage
distance
(mm)
Installa-
tion
(year)
62-B M1 SIR 2591 9855 1998
62-C M1 SIR 2591 7010 1996
64-V M2 EPDM/SIR 2591 8810 2002
64-F M2 EPDM/SIR 2591 8810 2002
In the first inspection, carried out in 2003, no corona was detected on the insulators (Fig.1). The electrical field distribution along each insulator presented a performance corresponding to a non-defective insulator (Figs. 2 to 5). The small variations on the curves (Figs. 3 to 5) were considered to be caused by the wetting and pollution combination over the insulator surface. These results showed than the insulators were in good operating conditions.
For validating the above, one of the insulators was removed from the line in order to visually review its surface, and later, it was reinstalled in the same tower. The reviewed insulator was that installed on the tower 62-C, because it had the longer operating time and the highest variations on its electrical field curve.
The insulator, with 8 years of operation, only had light degradation on its surface. The observed degradation was small erosions with around 1.5 cm long and 1.0 mm deep (Fig.6), in
different zones along the insulating surface. The erosions were results from the high dry band arcing activity on the insulator. In that moment, the degradation was not a risk for the insulator, but it would have to be periodically monitored.
B. 2004 inspection
In the inspection of 2004, corona activity was observed around the high voltage electrode of the insulators installed on the towers 62-C, 64-F and 64-V (Fig. 1). The electrical field
distribution curves (Figs. 3 to 5) for the 4 insulators showed a light increase into the insulator side close to the ground electrode, with respect to those obtained in 2003. Near the high voltage electrode (hot side), the electrical field curves did not present oscillating variations. Therefore, it was considered that the corona detected was mainly caused by the pollution
accumulation.
377
Authorized licensed use limited to: Tarbiat Modares University. Downloaded on September 26, 2009 at 07:59 from IEEE Xplore. Restrictions apply. The tower 62-C insulator was temporally removed from the line again. The visual review revealed than the major erosions had grown from 1.5 to 2 cm long and from 1.0 to 1.5 mm deep. In this inspection, it was also determined than the degradation did not represent yet a high risk condition for the insulator. Hence, it was reinstalled to the line.
62-B 62-C 64-V 64-F
no corona no corona no corona no corona
a) inspection performed in 2003
62-B 62-C 64-V 64-F
no corona corona corona corona
b) inspection performed in 2004
62-B 62-C 64-V 64-F
no corona corona corona corona
c) inspection performed in 2006
Fig. 1. Results of the corona visual inspections carried out on polymeric
insulators located in a highly polluted area.
1.7
1.9
2.1
2.3
2.5
2.7
2.9
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31
Number of shed
Electric field (Log)
2003 inspection 2004 inspection
Fig.2. Electric field along the polymeric insulator installed on the tower 62-
B, measured in several inspections performed in field.
1.7
1.9
2.1
2.3
2.5
2.7
2.9
3.1
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
Number of shed Electric field (Log) 2003 inspection 2004 inspection 2006 inspection
Fig.3. Electric field along the polymeric insulator installed on the tower 62-C, measured in several inspections performed in field.
C. 2006 inspection
In 2006, the inspection identified corona activity on the same insulators, namely, on the ones installed on the towers 62-C, 64-F and 64-V (Fig. 1). The electric field distributions, measured on such insulators, presented major distortions along the whole insulator, compared with those obtained in the previous inspections (Figs. 3 to 5). In this case, the electrical
field technique was not applied on the insulator 62-B, because it was detected no corona on its surface.
1.5
1.7
1.9
2.1
2.3
2.5
2.7
2.9
1 3 5 7 9 11131517192123252729
Number of shed
Electric field (Log)
2003 inspection 2004 inspection 2006 inspection
Fig.4. Electric field along the polymeric insulator installed on the tower 64-V, measured in several inspections performed in field.
1.5
1.7
1.9
2.1
2.3
2.5
2.7
2.9
1 3 5 7 9 1113151719212325272931
Number of shed
Electric field (Log)
2003 inspection 2004 inspection 2006 inspection
Fig.5. Electric field along the polymeric insulator installed on the tower 64-F, measured in several inspections performed in field.
The electrical field distribution oscillations on the zone close to the high voltage electrode were assumed to be resulted from
378
Authorized licensed use limited to: Tarbiat Modares University. Downloaded on September 26, 2009 at 07:59 from IEEE Xplore. Restrictions apply. severe damage on the insulators. Based on this, the 3 insulators (62-C, 64-F and 64-V) were removed from the line.
The 3 insulators actually had very severe degradation (Fig. 6). On the insulators 64-F and 64-V, the erosion, occurred during their 6 years in operation, caused the exposure of the
fiberglass rod to the environment close to the end fitting, which can lead to failure. In both ones, the degradation process was very similar, as can be seen from Fig. 6.
The insulator 62-C, with 10 years of operation, showed very deep erosion on its sheath near the high voltage electrode, the erosion being 2.2 cm long and 2 mm deep. Because the
exposure of the rod was imminent, it was considered that this erosion could affect the operation of the insulator. Therefore, the insulators 62-C, 64-F and 64-V were replaced by new ones.
ground side middle high voltage side Fig.6. Erosion observed on the polymeric insulator of the tower 62-C, in the inspection carried out in 2003.
62-C 64-V 64-F
Fig.7. Severe erosion observed on the polymeric insulators close to high voltage electrode of the towers 62-C, 64-V and 64-F, in the inspection carried out in 2006.
Later, the insulator 62-B was also removed from service, in order to validate its results obtained during the 3 inspections performed, which indicated that its operative condition was
good. In the visual examination, it was only found crazing along the insulator surface (Fig. 8), which is a very light degradation. From this way, it was proven that the condition of
the insulator is very well, and consequently, the insulator was reinstalled.
ground side middle high voltage side Fig.8. Light degradation observed on the polymeric insulator of the tower 62-B, in the inspection carried out in 2006.
VI. CONCLUSIONS
The diagnostic of most polymeric insulators in Mexico has been performed by using two techniques during the last 3 years, corona visual and electric field detection. These techniques have allowed detecting either cracking, erosion or tracking degradation on different insulators. According to the electric field results, it has been possible to establish if the degradation on the insulator represents a failure risk for the power line.
This diagnostic has also allowed to follow the insulator degradation progress from one inspection to another. The electric gradient increases as the degradation grows in the insulator. Thus, by carrying out the periodic diagnostic the long term performance of polymeric insulator can be followed.
Three insulators identified as high risk were removed from the line, and later were visually reviewed. The inspection showed that the insulators had indeed reached end of life. These insulators were working by approximately 4 and 10 years respectively. It means that the useful lifetime of polymeric insulators can be diminished under severe pollution conditions. Therefore the polymeric insulators must be frequently monitored in order to maintain the reliability of the power line. The use of these insulators has also reduced the number of maintenance works performed before on the transmission line insulators.
ACKNOWLEDGMENT
The authors wish to thank the engineers and workers of the Mexican utility (ComisiÛn Federal de Electricidad) for their contribution in the development of this project; especially to Engineers AgustÌn Villavicencio-Valadez, Froyl·n MartÌnez-Fonseca, and Fernando Guadalupe-Gonz·lez.
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