3.2. Typical dielectric spectroscopy results
The theoretical model describing the permittivity evaluation of materials vs. frequency and temperature, implies that any good quality oil sample will be characterized by a low εr′ value (ideally εr′ → 1) and a low εr″ value (ideally εr″ → 0) and therefore, tanδ→ 0 at all frequencies. In the absence of polarization processes these results should be temperature independent, implying that the examined samples are high purity oils being entirely free of aging byproducts or contaminants. For the purpose of this study the permittivity measurements were performed under four different oil temperatures, i.e. 20°C, 40°C, 60°C and 80°C. Such oil temperatures may be practically encountered around the hot spot regions of high power transformers.
Previous work [
12-
13] has established that the temperature dependent complex permittivity measurements at various frequencies can be utilized to validate the insulation capacity of power transformer oils. The proposed criteria for sample dielectric characterization were based upon the values of ε
r′ and tanδ at 20°C and the resulting variations with temperature [
13].
According to the above criteria and the obtained complex permittivity results, the investigated samples could be categorized in three distinct groups, as given in
Table 2. The resulting classification within each group was found to be as shown in
Figure 5.
Throughout this work, the circle markers represent data of oil temperature of 80 °C. The triangle markers represent oil temperature of 60 °C. The square markers represent oil temperature of 40 °C and the rhombic markers represent oil temperature of 20 °C.
3.2.a. Group-I: Oils that are in satisfactory condition for continued usage
These oil samples exhibit low ε
r′ values (practically measured to be of the order of 2.15±0.01 at 20°C). As the oil temperature is increased the real part of the relative complex permittivity (ε
r′) tends to be slightly reduced. Additionally, ε
r′ is almost frequency independent (
Fig.6a).
The oil samples of this group are also characterized by the very low tanδ values, which are measured in the range of 10
-4 to 10
-3 and are temperature independent at all frequencies (
Fig. 6b, 6c).
3.2.b. Group-II: Oils that may require reconditioning (dehydration/filtration) to ensure a prolonged and reliable service
The oil samples that are categorized in this group may exhibit slight disorders for at least one of the measured dielectric quantities. For example, if an oil sample provides low εr′ and tanδ values at high frequency region, but exhibits increased losses and therefore, higher tanδ values in the low frequency region (20 Hz - 1 kHz) with slight thermal dependence, it is classified in Group-II oil category.
Fig. 7 provides the average values of the dielectric parameters of the 43 samples within this group. According to these results the real part of the relative permittivity is found to be in the range of 2.19±0.01 at 20°C while the tanδ values are only slightly increased to 10
-3 at 20°C and show minor temperature dependence at lower frequencies (
Fig. 7b). All figures (
Figure 7,
Figure 8 and
Figure 9) are presented with same scales to enable for a direct comparison between corresponding data of oil samples in Groups I, II and III. Notice that for the ε
r′ and tanδ results of Group-II, the corresponding values are slightly increased at all frequencies and temperatures, compared to the Group-I.
3.2.c. Group-III: Oil samples in poor condition
Oil samples in this group are characterized by very high dielectric disorders of at least one of the measured parameters. This could be practically related not only to their relatively high humidity levels, but on the presence of additional polar contaminants and other possible aging (ionic/molecular) byproducts.
The average values of the investigated dielectric parameters of the 68 oil samples characterized in Group-III are given in
Figure 8. Here, the ε
r′ values are increased and are found to be in the range of 2.21±0.01 at 20°C. The tanδ values are increased up to 10
-2 level for oil temperatures of 20°C and the conductance results exhibit strong temperature dependence at all frequencies, especially in the lower frequency regime (20Hz-1kHz) where the ionic relaxation dominates.
The incorporated various byproduct concentrations mainly affect current losses and therefore, the overall tanδ values. The loss current intensification can be attributed to the polarizable inclusions originating from various sources, i.e. cellulose paper aging byproducts, chemically etched copper ions originating from the transformer windings due to the acidic oil media, ash formation by the oil degradation, gaseous byproducts created during dissociation of the transformer oil, etc. Presently, these byproduct concentrations require physicochemical and analytical techniques [
5-
6] to be uniquely identified, but without indicating trends towards total breakdown voltage deterioration input which is of primary concern. On the contrary, the direct measurement of electrical losses brings-in vital information concerning possible breakdown onset.
3.3. The corresponding physicochemical results
The physicochemical tests described in
Table 1 were performed in every mineral oil sample according to the corresponding ASTM procedure. Then, the average values of estimated physicochemical entities of all samples incorporated in each Group (I, II, and III) were evaluated, as shown in
Fig. 9.
Fig. 9a provides the average breakdown voltage under given electrode geometry as prescribed by the ASTM D877. According to these results there is a clear tendency for breakdown voltages to be reduced in oil samples having deteriorating permittivity characteristics. The acquired average breakdown voltage values for all Groups are above the 26 kV threshold, which is frequently considered as the minimum requirement for used oils. However, close comparison between samples might lead to the conclusion that this physicochemical measurement cannot be used as a stand alone prediction measurement of the expected oil service-life since in some of the Group-III samples the acquired dielectric breakdown values were high enough (∼31 kV).
Fig. 9b provides the average acidity levels of oils within each group, as determined by the ASTM D974, i.e. number of mg of KOH required to neutralize one g from each oil sample. According to the results of
Fig. 9.b. the acidity values are increased as the permittivity characteristics of the oil samples deteriorate, i.e. Group-III oil samples show higher acidity levels compared to the oil samples in Group-II and Group-I. The quoted average acidity values satisfy the maximum threshold requirement of 0.2 mg KOH/ oil g, but distinct samples exist in Group-III where the acidity exceeds 0.3 mg KOH / oil g. Acidity depends on aging byproducts, as well as on the concentration of additives, e.g. possible P.C.B. content in the oil matrix above 50 ppm.
Fig. 9c provides the interfacial tension values for oils within each group (I, II, and III). Measurements were performed according to the ASTM D971. According to the results of
Fig. 9c. the interfacial tension decreases as the permittivity characteristics of the oil samples deteriorate, i.e. Group-III oil samples exhibit lower interfacial tension compared to oil samples in Group-II and Group-I. Oil samples in Group-I have values within the suggested limits, while samples of Group II have values close to the minimum requirement of 24 dynes/cm and Group III samples exhibit unacceptable interfacial tension values (<24 dynes/cm). These results are in good accordance with the dielectric spectroscopy data and therefore, interfacial tension measurements can be utilized as a reliable approach for the overall oil condition.
Fig. 9d provides the average values of the relative density for oils within each group (I, II, and III). Measurements were performed according to the ASTM D1298. According to the results of
Fig. 9d. the density increases as the permittivity characteristics of the oil samples deteriorate. Though the experimentally obtained density values of all examined samples are at acceptable variations as given by the various manufacturers for aged insulating oils (0.840-0.900), it can be seen that the density values in Group-III oil samples is highly increased. This could be related to the dissociation byproducts incorporated in the oil matrix, i.e. chemical dissociation of insulation paper, etched copper ions [
14], free radicals of broken down hydrocarbon chains.
Fig. 9e provides, for each group, the average oil color number values (0.5-8.0) as determined by the ASTM D1500. According to the obtained results the oil color number raises as the oil permittivity properties tend to deteriorate. However, it should be emphasized that color is not always a reliable guide to product quality and should not be used indiscriminately in product characterization (ASTM D1500).
Fig. 9f provides the average values of the water content in oils (ppm max) within each group (I, II, and III). Measurements were performed as prescribed by the ASTM D1533. According to the results of
Fig. 9f, the water concentration (ppm) increases as the permittivity characteristics of the oil samples deteriorate. The maximum allowable concentration of water in used oils is 35 ppm for electrical applications below 69 kV. For the 150 kV components the max. water concentration in oil is 25 ppm and for the 400kV it is 20ppm. It can be noticed from the results presented in
Fig. 9f that the average values for all three groups are well below the 20 ppm limits.
Though most of the examined mineral oil samples collected from field operating power transformers fulfill the ASTM requirements of the physicochemical tests given in
Table 1, there exist significant variations among their permittivity characteristics. Permittivity differentiations emanate by the polarizable/ionizable aging byproducts within the insulating liquid. During the oil degradation process gases will evolve as the hydrocarbon chains break down leaving large free radicals in the liquid phase [
5]. The collisions of such free radicals usually generate large agglomerates of colloidal decay products with an average molecular weight of 450 to 550, that are no longer soluble in oil and precipitate as sludge or ash [
2]. The most frequently detected gases by HPLC in transformer mineral oils are O
2, N
2, H
2, CH
4, CO, CO
2, C
2H
6, C
2H
4, C
2H
2, C
3H
8 and other liquid hydrocarbons [
5-
6]. Limitations of Dissolved Gas Analysis (DGA) techniques rise by the fact that the Totally Dissolved Gas Compositions (TDGC) cannot be monitored in the liquid, since the gases can be dynamically either evolving or being absorbed, and the measured values will be the net effect of two competitive reactions of the traced specific gases.
On the other hand, the test methods prescribed by the Oxidation Stability of Mineral Insulating Oils in ASTM D2440 require laboratory environment for the time demanding absorbance tests in the visible spectrum.
Therefore, the proposed temperature dependent dielectric spectroscopy acquires direct information concerning the electrical energy loss and storage by the liquid insulation, thus allowing for systematic differentiation monitoring among the operational transformer oils.