This edited contribution to INMR by Kostas Velitsikakis and A. Kumar at TenneT TSO focuses on selection of sheath voltage limiters when considering charge transfer capability. Their electromagnetic transient analysis is the result of root-cause analysis regarding a failed cross-bonding joint of an underground cable system in a 380 kV Siphon Circuit in the Dutch EHV grid. The study considered circuit energization and evaluated overvoltages across the sheath interruption of cable joints as well as energy dissipation and charge transfer levels of the SVLs.

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In general, a cable system can be subjected to transient overvoltages resulting from:

a) switching actions, e.g., energization of the circuit, fault inception within the circuit and its subsequent clearance; and

b) fast-front overvoltages due to lightning strikes on nearby overhead lines.

Such overvoltages can stress the cable’s main insulation as well as the insulation of the sheath bonding system as well as accessories. Unless properly mitigated, such overvoltages could exceed the specified insulation withstand levels, leading either to a reduced lifetime of a component or to insulation degradation, potential dielectric failures and long repair times.

Long underground cable circuits have become more common in the Dutch transmission grid due to increasing number of HV and EHV expansion projects. Sectionalized cross-bonding has been the standardized sheath bonding design applied (as illustrated in Fig. 1).

International standards provide guidelines for selection of minimum sheath insulation withstand levels with respect to bonding lead lengths. However, there are few detailed guidelines for proper insulation co-ordination of a sheath bonding system. For maximum bonding lead lengths or for selection of sheath voltage limiters, no distinction is made with respect to nominal voltage of a cable system or if it is part of a Siphon circuit.

Below, focus is placed on the SVL selection when considering the charge transfer capability and its importance in the insulation coordination process to achieve a sufficient performance against transient overvoltages. Main findings and lessons learned are presented based on results of a cable cross-bonding joint failure investigation and root-cause analysis.

Description of Cable System & Failure Event

TenneT is the Transmission System Operator in the Netherlands and and also a part in Germany. The Dutch EHV grid operates at a nominal voltage of 380 kV and consists mainly of overhead line circuits. Nevertheless, in the western part of the grid, the so-called Randstad380 System is in operation, i.e. circuit connections consist of overhead line parts in combination with multiple and relatively long underground sections. The system under study, commissioned in 2018 and put into operation in 2020, refers to a double circuit connection between the two 380 kV substations A and B (see Fig. 2) and total circuit length is approximately 46 km.

Each circuit consists of three underground cable and three overhead line sections respectively. Due to transport capacity requirements, two cables per phase (Figs. 3 and 4) are applied that result in a total cable length of approximately 105 km. Sectionalized cross-bonding is applied with the following characteristics per cable section: one major section per cable system, 3 minor sections per cable system, 6 cross-bonding joints per cable system, 2 link boxes per cable system and each one equipped with 3 sheath voltage limiters (Fig. 5). Single-core cables are used as bonding leads, with length estimated at 20 m.

Table 1 summarizes the main information of the cable systems within the cable section 1 of the circuit. Table 2 provides the main data of the SVLs and of the surge arresters that are present at both transition ends of each cable section.

Failure Event

In Jan. 2023, one of the outdoor cable terminations failed at the transition point between the underground cable Section 1 and the overhead line. The failure resulted in a single phase-ground fault, which was correctly cleared within 70 ms by the differential protection of the cable system, as shown in the protection recordings of Fig. 6. Because the fault was detected within the protection zone of the cable section, the single-phase auto-reclosure function was blocked and the complete circuit was de-energized. The root-cause analysis concluded that the cable termination failed mechanically and no link was made to possible dielectric stresses due to transient overvoltages.

Nevertheless, following the repair, an HVDC voltage test was conducted to check the integrity of the cable sheath. During the test, an abnormally low resistance was detected at the sheath interruption of one of the six cross-bonding joints at the end of the first minor section as seen from S/S A. The laboratory investigations indicated traces of severe electrical activity on the sheath interruption ring, as shown in Fig. 7. Moreover, the System Operations data showed that both Siphon circuits are frequently switched, as an alternative measure to control the system voltages below the maximum allowable voltage of 418 kV, as specified in the Dutch grid code.

Based on the above findings and information, transient overvoltages were considered as possible root-cause of the cable joint failure. An electromagnetic transient (EMT) analysis was therefore conducted to evaluate performance of the insulation coordination of the sheath bonding system by analysing:

a. transient overvoltages at cross-bonding joint locations;
b. energy dissipation and charge transfer levels in the SVLs;
c. impact of bonding lead length on the resulting overvoltages;
d. impact of SVL selection on the charge transfer.

The EMT analysis focused on switching transients due to circuit energization.

EMT Analysis

For the purpose of the transient analysis, an EMT model was developed in EMTP-ATP. The model included detailed representation of the main components of the Siphon circuits (overhead line sections, surge arresters, underground cable sections, bonding leads and SVLs) and was extended several nodes further than Substations A and B to account for simulation of slow-front overvoltages due to switching events.

The transient simulations calculated the sheath-ground and sheath-sheath overvoltages at the sheath interruption points of Cable Section 1 of the circuit (as shown in Fig. 8). Moreover, energy dissipation and charge transfer of the sheath voltage limiters were monitored. Calculated values were evaluated against given lightning insulation withstand levels (LIWL) and SVL data sheet values (as summarized respectively in Tables 2 and 3).

Parametric Switching Analysis

A parametric switching analysis was conducted, by varying the energization instant in steps of 1 ms within half a cycle of the power frequency voltage waveshape. The analysis considered the simulation cases, as listed below:

• Case 1: Circuit energization from S/S A, i.e. circuit breaker at S/S A closes and circuit breaker at S/S B remains open.
• Case 2: Circuit energization from S/S B, i.e. circuit breaker at S/S A remains open and circuit breaker at S/S B closes.

In Case 1, the resulting peak overvoltages across the sheath interruption of the cross-bonding joint 1 are close to or slightly higher than the specified LIWL for all switching instances (Fig. 9). On the other hand, Case 2 results in significantly lower peak overvoltages. Although in both cases calculated energy dissipation levels remain well below given thermal energy withstand of the SVLs (see Fig. 10), Case 1 (irrespectively of switching instant) results in much higher charge transfer levels at both measurement locations (see Fig. 11).

Based on these findings, it can be concluded that energization of the Siphon Circuit from S/S A leads to stresses that could be problematic for the sheath interruption insulation of the Cable System of Section 1. Revised insulation coordination should consider either shorter lead lengths and re-location of the link boxes or selection of SVLs with lower protection levels – or a combination of both.

Impact of Bonding Lead Length

The overvoltage across the sheath interruption is the sum of the voltage drop in the bonding leads and the residual voltage of the SVLs [1, 11], as shown in Fig. 8. Considering the inductive behavior of the bonding lead, the voltage drop depends on the lead inductance and the derivative of the current that flows through the lead:

Longer leads result in higher inductance values; however, higher inductance values result in slower change in the current and, thus, in lower di/dt values.

As shown in Fig. 12, a non-linear increase of the inductive voltage drop occurs due to the cumulative effect of these two factors. For longer lead lengths, the voltage drop per meter decreases (see Fig. 13). Moreover, additional simulations indicated that an increase in the bonding lead length from 10 m to 30 m does not impact on the initial peak overvoltage across the sheath interruption as well as its steepness.

Impact of SVL Selection on Charge Transfer

Typically, two main parameters are considered in SVL selection process: a) continuous operating voltage, Uc, and b) protection level, Upl. In most cases, Uc is selected by considering the maximum induced voltages on the sheath during fault conditions. In some cases, the continuous operating voltage is selected to be even higher than the HVDC withstand voltage of the sheath; this allows the after-installation voltage testing of the sheath without the need for disconnecting the SVLs. Upl is selected by considering the insulation withstand levels of the cable sheath and of the cross-bonding joint in combination with the inductive voltage drop on the bonding leads.

Although international guidelines do not make specific reference to charge transfer capability, the latter can have significant impact on the SVL selection process. For example, should EMT studies conclude that higher class SVLs are required to meet the charge transfer criteria, this could significantly impact design of the link box and overall cable system design costs. On the other hand, poor SVL selection could lead to possible failures, leaving the sheath bonding system exposed to higher transient overvoltage stresses.

The following example case provides further elaboration on the above; the circuit energization simulation was repeated, by considering the characteristics of an SVL with a lower rated voltage (U_r=9 kV, U_c=7.2 kV, U_pl=27.4 kV_p). The sheath voltage limiter is still considered an acceptable option with respect to its protection level and the continuous operating voltage. Nevertheless, this SVL offers a lower voltage-current characteristic compared to the SVL of the reference case (Fig. 14). For this particular Siphon circuit, the switching transients resulted in excessive charge transfer levels (Fig.15) and exceedance of the given Qrs datasheet value.

The above research focused on selection of sheath voltage limiters when considering charge transfer capability. The latter is considered essential for insulation coordination of sheath bonding of a cable system to achieve sufficient performance against transient overvoltages. The analysis presented was the result of the root-cause analysis regarding a failed cross-bonding joint of an underground cable system in a 380 kV Siphon circuit in the Dutch EHV grid.

The electromagnetic transient analysis showed that the substation of switching determines peak overvoltages across the sheath interruption in the cross-bonding joint under study. More specifically, the peak overvoltages slightly exceed the specified lightning insulation withstand level of the sheath interruption when energizing the mixed cable-line cable from substation A. Moreover, bonding lead length is an important parameter for peak overvoltage across the sheath interruption. For longer lead lengths, inductive voltage drop per meter decreases, which results in a ‘saturation-like’ voltage drop-lead length characteristic.

Lastly, EMT analysis showed that SVL selection should consider charge transfer capability. Although the continuous operating voltage and protection level may meet SVL requirements, poor selection with respect to charge transfer capability could lead to exceeding data sheet guaranteed values. Possible failure of a sheath voltage limiter could leave the sheath bonding system exposed to excessive transient overvoltage stresses.

References

[1] CIGRE Technical brochure 797, Sheath bonding systems of AC transmission cables – Design, testing and maintenance, 2020
[2] IEC 62067, Power cables with extruded insulation and their accessories for rated voltages above 150 kV (Um=170 kV) up to 500 kV (Um=550 kV) – Test methods and requirements, 2022
[3] IEC 60840, Power cables with extruded insulation and their accessories for rated voltages above 30 kV (Um=36 kV) up to 150 kV (Um =170 kV) – Test methods and requirements, 2020
[4] IEEE P575/D13Approved draft guide for bonding shields and sheaths of single-conductor power cables rated 5 kV through 500 kV, 2014
[5] IEC 60099-5, Surge arresters – Part 5: Selection and application recommendations, 2018
[6] G. Hoogendorp, Steady state and transient behaviour of underground cables in 380 kV transmission grids, TU Delft, 2016
[7] Netcode elektriciteit, 2016
[8] K. Velitsikakis, A. Kumar, M. Faragalla, R. Zuijderduin, Failure Investigation Analysis for Switching Overvoltage Stresses in a Cross-Bonding Joint of a 380kV Siphon Underground Cable System in the Netherlands, CIGRE NRCC Symposium, 2025
[9] EMTP-ATP
[10] IEC 60071-4, Insulation coordination – Part 4: Computational guide to insulation coordination and modelling of electrical networks, 2004
[11] A. Khamlichi, G. Denche, F. Garnacho, G. Donoso, A. Valero, Location of sheath voltage limiters (SVLs) used for accessory protection to assure the insulation coordination of cable outer sheath, sectionalising joints and terminations of high voltage cable systems, CIGRE Session, Paris, 2018

The post Switching Overvoltage Stresses on Sheath Voltage Limiters: Failure Investigation appeared first on INMR.

This edited past contribution to INMR by Dr. S. Kühnel and Prof. Stefan Kornhuber of the University of Applied Science Zittau/Görlitz as well as Dr. Christiane Baer of Wacker Chemie reported on pollution flashover performance of partially coated glass cap & pin insulators. In addition, such insulators were investigated under salt fog conditions to evaluate stability of their hydrophobic properties.

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Insulator String & Coating

Dimensioning Insulator String

Pollution flashover of different cap & pin type insulators has already been investigated and it has been determined that even partial coating can lead to significant increase in flashover voltage compared to an uncoated insulator. For example, a systematic investigation of the pollution flashover of partially coated insulators was performed in 2017 using cylindrical model insulators to better understand the flashover process (e.g. extension of pre-arcs) and to estimate resulting flashover voltage.

Several parameters have to be defined in order to apply this same model to glass cap & pin insulators, including maximum voltage drop and level of pollution. In this investigation, a 110 kV insulator string consisting of PSW 120 cap & pin insulators was chosen (see Fig. 1).

Taking the dimensions of the insulator disc into consideration, a string consists of 7 to 8 units with respect to minimum required air gap (see Table 1).

Proper dimensioning of a glass & pin insulator string requires consideration of their insulation capability under polluted conditions. In this regard, an insulator string for heavy pollution (according to IEC 60815) usually consists of 8 discs (see Table 2).

Recommendations in IEC 60815 and IEC 60507 were chosen for dimensioning the silicone coating. In this way, an SDD level up to 0.7 mg cm^-2 and a volume conductivity of the pollution liquid greater than 42 mS cm^-1 are assumed. Maximum volume conductivity is defined based on volume conductivity of seawater, i.e. 50 mS cm^-1.

Dimensioning Coating Length & Position

Calculation of coating length (namely the creepage distance of the insulator that is covered by the coating) requires information on the maximum stress (i.e. maximum voltage drop) of a single glass insulator disc. As a first step, distribution of the electric potential (electrostatic field) of a dry insulator string, consisting of 8 PSW 120 glass insulator discs was numerically calculated using COMSOL Multiphysics. The top end of the string is grounded and the bottom end exposed to high potential (i.e. 71 kV). Since the insulator string is mounted on the cross-arm of a tower, this typically leads to non-uniformity of potential distribution. Highest electric potential drop across one glass insulator disc is calculated to be nearly 18 kV (see Fig. 2), which is in line with most published values.

Required length of coating is then calculated using this maximum voltage drop as well as the empirically determined specific flashover voltage of a silicone coating with droplets, based on the formula below:

Applying this formula, coating length needs to be 5.2 cm so as to achieve a flashover voltage of 18 kV at 50 mS cm^-1.

Defining Coating Position

The upper side of the glass insulator disc is excluded from consideration because of lower hydrophobicity retention. Similarly, the surface area close to the fittings is also excluded since it shows high electric field stresses (>5 kV cm-1) under dry conditions (see Fig. 3). Therefore, partial discharges can occur and reduce the coating’s hydrophobicity.

Respecting these considerations, two coating patterns were evaluated in detail (see Fig. 4).

When calculating electric field of the insulator string under wet conditions, all uncoated areas are assumed to show a film layer of the electrolyte and thus defined to be a resistive layer at floating potential. Coated areas are assumed to show a hydrophobic droplet layer and thus the insulating capabilities of air.

Both coating types (Types B and C above) were investigated with lengths of coated sectors of 5.2 cm and 9 cm respectively, resulting in theoretical pollution flashover voltages of 18 kV and 28 kV. Calculations were performed assuming radially and axially uniform pollution on each insulator disc. The potential calculated along the insulator string under wet conditions showed more uniform distribution in the middle axis of the string compared to under dry conditions (see Fig. 5). Maximum voltage drop over one insulator disc decreased to about 12 kV.

When considering a single insulator disc under wet conditions, the voltage drops over the coated area. Therefore, the highest electrical field stress is at the transition between the silicone coating and the conductive film layer (as shown by the red arrow in Fig. 6 for coating Type C). This transition point could become challenging for long-term stability of hydrophobicity in service since any partial discharges that occur can reduce this desired property.

Experimental Verification

Pollution Flashover Voltage

Test Procedure & Set-up
Single PSW 120 type cap & pin insulators with Types B and C coatings were evaluated with respect to pollution flashover voltage. Artificial pollution of the insulators was achieved using two different methods: glass surfaces were polluted by dipping the insulator into a slurry made of water, 20g pyrogenic silica (Wacker HDK® N20) per litre and sodium chloride. A pressure sprayer was used to spray a solution of water and sodium chloride onto those areas with silicone coating, resulting in a uniform layer of droplets on the surface (see Fig. 7). All tests were carried out in the suspension orientation.

The 50% pollution flashover voltage was determined by the up-and-down test method and set-up. After each electrification, insulators were cleaned thoroughly with water to remove all residues of the pollution layer. To ensure maintaining Hydrophobicity Class 1 in the silicone coated areas of the insulator, a recovery period of at least 48h was allowed after each flashover. A high speed camera evaluated the flashover process. Every test series consisted of at least 10 tests to ensure statistical confidence and all values were reported as arithmetic means with 95% confidence intervals.

Test Results
Fig. 8 shows the pollution flashover voltages for partially coated, fully coated and uncoated insulators. Against expectations, insulators with Type B coating showed about the same pollution flashover performance as uncoated insulators in those tests where liquid conductivity was 50 mS cm^-1. A flashover voltage of 18 kV was calculated and a voltage of about 11.5 kV measured. Pre-arcing activity could be observed before the start of flashovers. In the case of the Type C coating, a significantly lower pollution flashover voltage than calculated was also measured for liquid conductivity of 50 mS cm^-1. Results for conductivity of 1.7 mS cm^-1 were in the range predicted by the model.

Both coating types showed pollution flashover voltages at high pollution conductivity that were much lower than had been predicted. Observations of the flashover process were then performed to investigate the reasons (see Fig. 9).

It was seen that, in cases of flashover, a relatively long filament bridges a large portion of the coated area (i.e. 40 to 50%) and this leads to reduction in effective coating length as well as flashover voltage. This effect had not been observed in past studies using slim cylindrical insulators, likely caused by insufficient supply of current necessary for flashover on these slim insulators.

To compensate for this effect, an effective coating length was introduced according to the following:

Recalculating pollution flashover voltages for both coating types, this time using effective coating lengths, showed good accordance of measured and calculated values (see Fig. 10).

As conclusion, the pollution flashover calculation model has to be modified by including reduction in effective coating length by a geometric factor.

Hydrophobicity Status Under Salt Fog Conditions

Test Procedure & Set-up
Salt fog tests were carried out according to IEC 62217 to evaluate stability of the coating layers on the glass cap & pin insulator under investigation. During these tests, fully coated insulators as well as a Type B coating were placed in a salt fog chamber of 4.5 m³ volume (see Fig. 11).

Salt fog was generated using turbo sprayers and deionized water with sodium chloride content of 8 kg m^-3 (i.e. conductivity at 20°C of 13 mS cm^-1). Amount of precipitation was on average 0.02 ml h^-1 cm^-². Test voltage was set to 12.8 kV (50 Hz AC), according to specifications as per IEC 62217.

Leakage current was measured and hydrophobicity status evaluated once the test was completed after 1000h. In addition, leakage current (as an indirect measure of hydrophobicity) was also measured during the test.

Test Results
Fig. 12 shows the leakage current over the entire 1000h test duration.

Immediately after the test, hydrophobicity was evaluated by the spray method, according to IEC/TS 62073. Table 3 summarizes the findings.

Leakage current of insulators in the suspension configuration remained stable at the low level at 0.04 mA over the entire test time, which shows that at least a portion of the coating remained hydrophobic, even after the 1000 h test duration. This was confirmed by the hydrophobicity status at the end of the test.

For both partially and fully coated insulators in the suspension configuration, the bottom side showed a good hydrophobicity (HC 1-2). The topside of the fully coated insulator showed reduction in hydrophobicity to HC 4-5. Given the selected test conditions and for the type of insulator chosen, the bottom coating area appeared to be more important than the topside with respect to hydrophobicity.

The leakage current trend was different for insulators in the tension configuration. After about 50h and 200h respectively, leakage current for both types of coating began to increase. It is assumed that this was caused by more intense precipitation in the glass cap ribs and hence more intense wetting and electric field stress. Higher leakage current of insulators in the tension configuration, due to greater reduction in hydrophobicity, has also been determined for composite insulators during salt fog testing. Leakage current of the partially coated insulator started to further increase after about 700h. This can be interpreted as due to partial loss of hydrophobicity, as confirmed by its Hydrophobicity Classification. While the bottom of the fully coated insulator showed HC 1-2, the partially coated insulator had only HC 4-5.

Summary

This research dealt with dimensioning of partial silicone coating for a 110 kV glass cap & pin insulator string. Required string length was dimensioned with respect to insulation length for the pollution class ‘heavy’. The pollution flashover model based on slim cylindrical insulators was adapted and required coating length calculated based on empirical data from these model insulators. Coating position was chosen by using numerical calculations of the electrical potential and field. These calculations were carried out for insulator strings consisting of partially coated glass cap & pin insulators.

Calculated pollution flashover voltage for two types of coating arrangements was verified using an artificial pollution test. While in the case of low liquid conductivities, calculated values fell in the range of those being measured, for high liquid conductivities measured flashover voltages were significantly lower than calculated values. For the applied artificial pollution test, a high speed camera revealed ‘electrolyte jet bridging’ of portions of the coating, just before flashover. Thus, effective coating length was reduced and a lower flashover voltage measured under this type of pollution. A correction factor for the model was therefore introduced.

Finally, stability of hydrophobicity on partially coated glass cap & pin insulators was evaluated under salt fog conditions and findings compared to fully coated insulator discs. Overall performance of hydrophobicity stability was found to be sufficient to achieve efficient leakage current suppression, even after 1000h salt fog testing.

As a general conclusion, a partial coating of less than one-third of the creepage distance of glass cap & pin insulators can improve pollution flashover performance and also show satisfactory long-term performance with respect to hydrophobic behaviour. The approach used in this research has demonstrated the performance of a minimal partial coating, optimized in both coating length and position.

For dimensioning in service, a proper safety margin needs to be considered, i.e. coating only the lower surface of a glass cap & pin insulator can be seen as a practical solution. From the perspective of application, any minor defects or damage to the coated layer on glass cap & pin insulators can still offer effective leakage current suppression and high pollution flashover voltage, so long as the coated area on the lower insulator surface remains intact.

References

[1] G. Lange, R. Bärsch, J. Lambrecht, H. Liebermann and u.a., “Erste Betriebserfahrungen mit einem Siliconcoating auf Porzellanstützern unter natürlichen Fremdschichtbedingungen,” Elektrizitätswirtschaft 97, pp. 34-41, 1998.
[2] Z. Jia, S. Fang, H. Gao, Z. Guan and u.a., “Develepment of RTV Silicone Coatings in China: Overview and Bibliography,” IEEE Electrical Insulation Magazine Vol. 24 , pp. 28-41, März 2008.
[3] S. Kim, E. Cherney and R. Hackam, “Suppression Mechanism of Leakage Current on RTV Coated Porcellain and Silicone Rubber Insulators,” IEEE Transactions on Power Delivery, Vol 6, No. 4, pp. 1549-1556, 1991.
[4] G. Karady, M. Shah and R. Brown, “Flashover Mechanism of Silicon Rubber Insulators used for Outdoor Insulation – Part I; Part II,” IEEE Transactions on Power Delivery, Vol. 10, No. 4, October 1995.
[5] J. Liebermann, “New effective ways toward solving the problem of contamination of porcelain insulators,” Refractories and Industrial Ceramics, vol. Vol 43, pp. 55-64, 2002.
[6] R. Bärsch, “Polymere Isolier- und Funktionswerkstoffe für Hochspannungs-isolatoren und Kabelgarnituren – Beanspru-chungen, anwendungsspezifische Eigenschaften und Prüfverfahren,” in RCC-Fachtagung, Tagungsband, Berlin, 06.-07. Mai 2009.
[7] S. Kühnel, S. Kornhuber, R. Bärsch, J. Lambrecht, “Evaluation of the Pollution Flashover Voltage of Glass-Cap-Insulators with defined uneven Silicon Coating,” VDE-Fachtagung Hochspannungstechnik, 14.-16. Nov. 2016.
[8] S. Kühnel, S. Kornhuber, R. Bärsch and J. Lambrecht, “On the Pollution-Flashover-Behaviour of partially Silicone Coated Insulators,” 20th International Symposium on High Voltage Engineering, 2017.
[9] “DIN EN 60071-1 – Isolationskoordination Teil 1: Begriffe, Grundsätze und Anforderungen,” 2006.
[10] “DIN IEC/TS 60815-2 – Auswahl und Bemessung von Hochspannungsisolatoren für verschmutzte Umgebungen,” VDE Verlag GmbH, 2008.
[11] “IEC 60507 – Artificial pollution tests on high-voltage ceramic and glass insulators to be used on a.c. systems,” 2013.
[12] H.-D. Held, “Kühlwasser: Verfahren und Systeme der Aufbereitung, Behandlung und Kühlung von Süsswasser, Brackwasser, Meerwasser in der Industrie,” Vulkan-Verlag GmbH, 2000.
[13] R. Fischer and F. Kießling, Freileitungen: Planung, Berechnung, Ausführung, Berlin: Springer-Verlag, ISBN 978-3-642-56738-4, 2013.
[14] “IEC TS 62073 – Guidance on the measurement of hydrophobicity of insulator surfaces,” 2016.
[15] IEC 62217 – Polymeric HV insulators for indoor and outdoor use – General definitions, test methods and acceptance criteria, 2012-09.
[16] J. Seifert, R. Bärsch, “Bewertung des Kriechstreckendesigns von Silikonverbundisolatoren unter dem Aspekt von Fremdschicht-Bauartprüfungen und langjährigen Betriebserfahrungen,” in ETG-Fachbericht 99, VDE-Verlag, 2005, pp. 47-54.

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The post Pollution Flashover Behaviour of Hydrophobic, Hydrophilic & Partly Hydrophobic Coated Glass Insulators appeared first on INMR.

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Transmission Structure in the Clouds

Following destruction by avalanche of towers on two 300 kV circuits in the coastal mountains of British Columbia, Canada during the winter of 1954-55, an engineer named Brian White proposed the concept of catenaries on which phase conductors would be supported. Several years ago, another engineer, Peter Catchpole, utilized the same concept for that double circuit line, one span away and for much the same reason.

There are now two such ‘catenaries’ in a row on that line, both utilizing cables (circa 1160 m long for that from 1955 and about 1220 m for that built in 2008). The catenaries permit a span for the two circuit’s six very large conductors (3,364 kcmils) of circa 2450 m from one pair of standard lattice towers to the next. In other words, over an area of some 1250 x 2500 m across an avalanche prone valley, there are no towers at all. The vertical design load on each suspension insulator string is 75 tons/ phase due to heavy ice accumulation. Access for inspection and maintenance is by helicopter pads mounted on the cables and about 150 m above ground.

Tower in Shenzhen Designed for 4 Circuits

Carrying four 220 kV circuits might normally require rather tall towers. However, engineers in China designed a structure that accomplishes this with lower height. The line, which is probably unique in the world, utilizes composite insulators in suspension and glass strings in tension, passes a rapidly developing area near the Baoan Airport, just outside of Shenzhen.

Stately Towers Influenced by Maritime History

A transmission line running through northwestern France evokes the region’s maritime tradition through the use of imposing structures that mimic masts of sailing ships. These tall, elegant towers were reportedly many times more expensive than conventional lattice type alternatives however design, not cost, was apparently the key consideration for RTE, the French grid operator.

Use of such special designs is still relatively new in overhead transmission but is expected only to grow as appearance of lines becomes key to the process of obtaining required public approvals.

Towers Are Eye-Catching Feature Near Highway

Anyone driving from the center of the Chinese city of Jinan to its airport will pass and almost surely notice elegant 220 kV cable transition towers located only meters from the highway. Many such towers see the bulky terminations mounted in an elevated position on the structure, giving it an unwieldy top-heavy appearance. Moreover, the cables, being much thicker than the overhead conductors, add even more unsightly mass from a visual perspective. In this case, designers have dropped the overhead conductor to ground level terminations in an unusual and elegant fashion using a series of angled supports. The overall effect is to turn what might have been a bulky eyesore into what can best be described as a modernistic metallic sculpture.

Futuristic Cable Tower in Korea is One of a Kind

Daejeon, one of the largest cities in South Korea, has been promoting itself as the epicenter of the country’s cutting-edge science sector. With this in mind, engineers at Korea Electric Power Corp. attempted to contribute to this image by designing a one-of-a-kind cable transition tower situated at a busy highway interchange. While relying on conventional insulators, the structure is anything but conventional, leaving the impression of atomic physics.

Tower Developed Based on Capabilities of Composite Insulators & Arresters

The rapid development of hollow core composite insulators as well as polymeric housed surge arresters starting in the early 1990s together provided the impetus behind this innovative 400 kV tower, developed and tested by engineers at Sweden’s STRI. The goal was to utilize the high mechanical strength of the FRP tube in the insulator and the lightweight arrester to ‘de-clutter’ the typical HV line, substituting only four key components for what might otherwise be lengthy insulator strings as well as overhead ground wire. The concept, perhaps inspired by the Trident configuration used on distribution lines in places such as the United Kingdom, excels from the standpoint of efficiency but apparently has so far found only very limited application in Norway due to its comparatively high cost and ‘top heavy’ appearance.

Bold Towers Provide the Real Aesthetics Along Sensitive 735 kV Line

The Canadian province of Québec was especially hard hit by the great ice storm of January 1998, losing hundreds of transmission towers and seeing one region southeast of Montreal left without power for weeks. In order to strengthen the grid supplying the region against similar events, engineers at Hydro-Québec sought permission to construct a new 735 kV line that would run along one of the city’s most traveled highways. Public opposition was high and, in order to obtain required approvals and meet the demands of local farmers, key considerations were high aesthetics and small footprint. The striking tubular portal suspension towers one finds along a line section near a scenic river crossing were originally the prototype for the entire line. However, due to higher cost and longer lead-time to procure materials, lattice type towers of similar portal design concept ended up being specified to dominate the line.

Line Designed for Minimalism Yet Accomplishes Much

The Wintrack transmission line design now being used by Dutch grid operator TenneT (see INMR Issue 99, Q1, 2013) is a bold departure from lattice structures of the past. Sleek, with a highly modernistic appearance, Wintrack is perhaps the role model for the future of power transmission in crowded Europe. In this respect, perhaps it’s only fitting that it was developed in that continent’s most densely populated country. But stunning appearance is far from the only advantage, with the added benefit of significantly reduced line corridors due to lower magnetic fields from the line’s conductor configuration. Structural steel and foundation costs tend to increase as footing dimensions of a transmission structure decrease. Therefore, one of the goals for TenneT engineers was finding the optimal balance between a comparatively small footing, to satisfy the criterion of minimalism, and reasonable material and construction costs.

Towers Designed to Surround Line

One of the interesting design variants available to Chinese power engineers is a tower type that encloses the phase conductors of EHV lines. In this case, on a line running near the new EPRI UHV Test Facility near Beijing, a unique arrangement of V-string composite insulators supports 18 sub-conductors

Line Design Shines for Simplicity and Low Impact

The 220 kV Mudarra-La Olma line, running through a section of mainly agricultural land near the Spanish city of Vallodolid, was one of the first projects by the country’s grid operator, Red Eléctrica de España, that utilizes horizontal Vee assemblies of composite insulators. Utilizing only one conductor per phase, the towers on this line were designed to one day accommodate two circuits.

What makes this tower design remarkable is its simplicity and unusually low visual impact, even though running through flat agricultural terrain.

The post The World’s Remarkable Transmission Structures appeared first on INMR.

This edited past contribution to INMR by Laura De Fina, Armando Pastore and experts at GE Vernova Grid Solutions, in cooperation with Alberto Pigini, discussed pollution design of HVDC-UHVDC bushings for outdoor applications based on IEC/IEEE 65700-19-03, now under revision.

PFISTERER

Germany

Hitachi Energy Transformer Components and Service

Switzerland

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In some HVDC projects, while the transformer is placed externally, the bushings are installed with their airside insulators inside the valve hall. Under these conditions they are protected from external ambient conditions (see Fig. 2). However, at other HVDC substations, even though the transformers are again outdoors in the AC yard, connection to the DC valve hall is achieved by means of wall bushings. In this case, both the bushings on the transformer and the wall bushings on the converter side of the valve hall building are exposed to the external environment.

Similarly, DC yards are external in some HVDC substations while at other projects they are placed inside a structure, next to the DC valve hall. In this case, the wall bushings that connect the valves to the DC line can either have their line side exposed to external ambient conditions or these can be entirely indoors (see Fig. 3). Where present, DC reactors can also be placed entirely outdoors and have their bushings exposed to external ambient conditions. Alternatively, the bushings can be installed with the airside of the insulator in the valve hall and protected from ambient pollution (see Fig. 4).

The following discussion focuses on design of external insulation of bushings, both on converter side and DC side of HVDC substation, given the specific voltage waveforms seen as well as possible impact of environmental outdoor factors such as pollution. It is important to note that the creepage and arcing distances calculated in the examples provided below refer only to pollution performance issues. To select the proper insulator for the bushing, it is also necessary to evaluate all other relevant design aspects, including lightning, switching and AC tests, which include altitude correction if the substation is at an altitude greater than 1000m asl. Finally, installation aspects must also be respected in order to guarantee proper clearance distances from nearby walls or other equipment.

Outdoor Bushings at HVDC Converter Stations

Under operating conditions, bushings installed in an HVDC converter station are subject to voltage waveforms that can differ from one another other depending on the following:
• position of bushing in the substation, i.e. DC valve side or converter transformer side.
• type of converter technology and its topology, i.e.: LCC (depending on number of six-pulse bridges) or VSC (symmetrical or asymmetrical topology).

This differentiation is considered in paragraph 3.1.2 and 3.1.3 and also in the Annexes in the IEC standard now under development/revision. In particular, Annex C contains a list of typical HVDC transmission configurations, showing how the DC voltage is reflected on the AC side: for LCC systems this depends on number of six-pulse bridges and position of bushing with reference to these bridges; for VSC, this depends on the symmetrical/asymmetrical converter topologies.
There are a number of different application scenarios:

Type a: Bushings for Pure DC Applications

DC bushings subject to a DC voltage with only a small AC voltage ripple (e.g. the bushing on the high voltage side of a DC converter valve (see Figs. 5 to 8).

Type b: Bushings for Combined Voltage Applications

A DC bushing subject to a large AC voltage superimposed on a DC bias voltage, e.g. bushings applied to the valve winding side of a converter transformer (see Figs. 8 & 9)

Type c: Bushings Not Subjected to DC

This could be transformer bushings or wall bushings connected to the AC side of symmetric VSC converters (see Fig. 11). Such bushings see a quasi-sinusoidal voltage waveform (see Fig. 10) due to adoption for AC/DC conversion of several discrete voltage levels, as in a modular multi-level converter (MMC) VSC system. Being subject to a voltage stress close to that in AC, their design from the pollution point of view is not considered in this discussion since this is already covered in IEC TS 60815-1, 2 and 3.

Determining Voltage for Bushing Design from Viewpoint of Pollution

For Type a bushings (i.e. bushings for pure DC applications), the DC voltage dominates even if a mix of harmonics can be present. For example, Fig. 12 depicts idealized voltages across an unloaded 6-pulse bridge and across an unloaded 12-pulse bridge configuration. The base voltage to be used in design of such bushing insulators from the pollution point of view is the rated DC continuous voltage. Peaks due to ripples are not considered.

In a combined voltage application, bushings are subject to voltage wave shapes where complex alternating voltage waveforms superimpose on DC voltages.

For Type b bushings (i.e. bushings with combined voltage, as in the case of LCC HVDC transmission), continuous operating voltages at various locations within an LCC HVDC converter station could be a combination of direct voltage, fundamental frequency voltage, harmonic voltages and high frequency transients, depending upon location. For example, Fig. 14 shows typical waveforms of continuous operating voltages to earth (G) for a bushing (excluding commutation overshoots) at various locations at an LCC HVDC converter station with two 12-pulse converters in series per pole. Similarly, Fig. 15 shows waveshape for a 12-pulse bridge where C represents line to ground voltage waveform for the top transformer (Y-Y) and D is actual line to ground voltage waveform for the bottom transformer (Y- ∆).

In the case of a VSC asymmetrical arrangement, Fig. 16 represents a typical idealized voltage waveshape at the transformer side: a dc offset is present on a quasi-sinusoidal waveshape.

Peak voltages of short duration, as in Figs. 14 & 15, can be assimilated to overvoltages and are not considered in engineering practice to verify performance under steady state conditions, e.g. as under pollution. In the case of pure AC and DC, design under pollution is not carried out with reference to peak but rather to rms voltage. A more complex case is when combined voltages are present and it is then necessary to define an equivalent voltage stress for design and testing purposes.

For a bushing for combined voltage application, the issue remains whether this equivalent voltage should be assimilated to AC or DC. Experimental research involving small insulator samples has shown that the impact of the DC component on the 50% peak flashover voltage of the insulator under pollution (i.e. V50,hybrid,pk = VAC,pk + V50,DC) is reduced by up to the ratio 40%/60% of the DC component/AC peak voltage. This suggest the possibility of adopting a reasonable threshold level for the DC component, below which use of AC Technical Specifications (i.e. IEC TS 60815-2 or IEC TS 60815-3) to size the insulator under pollution could be carried out in place of using that for DC (IEC TS 60815-4).

Pending additional investigation, however, a conservative design is made (also for combined voltages) with regard to the more conservative DC specification and with reference to voltage U_b, determined as follows (as per the new IEC standard now under development):

with
– U₁ the rated continuous DC voltage

with

– U_dm the highest DC voltage per valve bridge across each six-pulse bridge for LCC and across the whole converter for VSC;
– U_vm is the maximum phase-to-phase AC operating voltage of the valve windings of the converter transformer on which the bushing will be assembled.
– N is, for LCC, the number of six-pulse bridges in series from the neutral of the DC line to the converter bridge connected to the bushing when mounted on the converter transformer \ wall bushings installed on the ac-side of the converter valve. For VSC_sym N is equal to 0.5. For VSC_asym N is equal to 1;

Annex E of the updated standard under development contains examples of calculating creepage as a function of bushing position in the substation as well as HVDC converter station layout and technology.

Definition of DC Pollution Classes

Since pollution classes are not yet defined in IEC 69815-4, the following case examples are based on the pollution classes proposed by Alberto Pigini at a recent INMR WORLD CONGRESS (see Table 1), with the note that in the case of DC these have to refer to measurements on energized insulators.
DC pollution classes cannot be determined based on the indications found in IEC 60815-1 (e.g. Table 3 or Figs. 1, 2 and 3). Rather, these require different estimates because dc insulators accumulate a higher volume of pollutants due to a constant electrostatic field along their length. For example, if pollution site equivalent salinity (SES) for AC is estimated at between 14 and 40 kg/m³ (i.e. Fig. 18 thus defining pollution site severity as medium), the corresponding values estimated in DC would fall between 40 and 112. This would classify the site as ‘heavy’ pollution, assuming a ratio of DC to AC contamination of K_p=2.8.
Rough indications to convert estimates of pollution severity from AC to DC can be obtained in Table 1 of IEC 60815-4. But as pointed out in the same TS, “In view of the large range of possible values for K_p, it is highly recommended to determine the DC site pollution severity by measurements made on d.c. energized insulators, for as long a period as possible and including any seasons likely to result in higher accumulation, in order to get a more precise estimation of the d.c. severity.”

The above values are assumed to be derived from measurements performed on reference cap & pin or small diameter long rod insulators energized under DC voltage.

Evaluating USCD According to IEC 60815-4

Once pollution severity class has been defined, strict determination of creepage distance required is made according to IEC 60815-4. To take into account assumed lower contamination found on large diameter insulators (in accordance with IEC 60815-4), the severity values in Table 1 must be multiplied by a factor, Kd, which takes the effect of diameter on the pollution accumulation into account:

where D₀ = 250 mm

Since there are only a limited number of bushings in parallel, the statistical safety factor, K_s (applicable when there are many insulators in parallel), is not considered. Applicable SES can then be determined using the following equations:

• Pollution Type A:
· SDD_DC=SDD x K_d

• Pollution Type B
· SES_DC=SES x K_d

Finally, required RUSCD can be determined from the following equations:

For Type A pollution:
• Non-HTM materials: RUSCD_dc = 110 x SDD ^0,33
• HTM materials: RUSCD_dc = 65 x SDD ^0,25

For Type B pollution:
Non-HTM materials: RUSCD_dc = 15 x SES^0,33
HTM materials: RUSCD_dc = 15 x SES^0,25

These equations are applicable to reference insulators (i.e. cap & pin insulators or station insulators with average 250 mm diameter installed at sea level or up to an altitude of 1000m and with a profile close to that used to determine the reference unified specific creepage distance (creepage factor, CF, ratio between creepage distance and arcing distance of about 3.5).

The USCD for bushings is determined, taking into account insulator diameter and installation altitude, according to the following equations:

USCD= RUSCD_dc× C_d×C_a

where enhancement coefficient, C_d, is:

NOTE: Since hydrophobicity of high-grade silicone rubber materials can experience progressive reduction in certain situations, it is advisable to size insulators with silicone sheds as HTM material with risk of loss of hydrophobicity.

The coefficient, C_a, is:

The above USCD value is applicable for insulators with creepage factor (CF) of about 3.5. Higher USCD may be necessary in consideration of the lower efficiency of profiles with higher CF. However, present quantitative indications cannot be given and have to be based on performance of the specific insulator as determined by laboratory testing. In the following example, influence of CF is considered negligible up to a value of about 4.

Example of Determining Bushing Arcing Distance

Once USCD is evaluated, arcing distance can be calculated as follows:

Below are examples that report on minimum arcing distances necessary as a function of system voltage and pollution class, considering:
– typical diameters of insulators as a function of system voltages;
– insulators with creepage factors CF=3.
Based on the typical bushing diameters in the following examples, a simplified relationship is assumed between average bushing diameter and rated system voltage, for both polymeric and porcelain housings:

Fig. 19 compares USCD values calculated for ceramic and composite insulators for different pollution classes, from very low to very high. This determination was made considering Type B pollution (simulated in laboratory by salt fog tests). Similar results could be obtained for Type A pollution criteria.

It is immediately clear that higher creepage distances are required for ceramic compared to composite insulators and this difference increases significantly in high pollution sites and with converter station voltage level. For example, in a lightly polluted site, a 300 kV composite bushing insulator requires a USCD of 30 mm/kV while a porcelain insulator needs 38 mm/kV; in a medium polluted environment an 800 kV composite bushing insulator requires around 42 mm/kV while this increases to 64 mm/kV in the case of a porcelain insulator.

The difference in specific creepage distance requirement between porcelain and composite insulators is also due to the lower influence of diameter on USCD in the case of HTM compared to non-HTM materials. As voltage (and consequently diameter increases), the USCD requirement remains almost constant for composite material at any specific pollution level. But in case of porcelain insulators, this increases with voltage/diameter. Therefore, the USCD requirement for a porcelain insulator in highly polluted sites is such that it becomes unfeasible because of excessive length.

Moreover, porcelain insulators are not recommended for DC wall bushing applications since they have a higher risk of flashover under rain. In such situations, part of the insulator remains dry (due to the shielding effect of buildings), resulting in uneven wetting of the ceramic surface due to its hydrophilic property. This can lead to increased field in the dry area, leading to flashover. In fact, application of composite insulator housings for bushings and similar devices has long been applied to successfully resolve flashovers at HVDC stations. These flashovers occurred due to uneven wetting of external insulators, such as horizontally mounted bushings, and this phenomenon was independent of creepage distance.

In general, the arcing distances prescribed by required USCD for both porcelain and composite envelopes in high pollution sites require considering the feasibility of outdoor versus indoor solutions. Indeed, the preferred solution for HVDC transformer bushings above a certain voltage is already indoor installation because of pollution requirements.

Even for outdoor wall bushings, the only solution possible is with composite envelopes in order to limit total bushing length and related mechanical issues. For composite insulators operating in medium pollution environment, 39-43 mm/kV is required while for heavy pollution this becomes 50-56 mm/kV. In the case of very heavy pollution, this requirement becomes 60-66 mm/kV (see Fig. 21). Many HVDC installations these days, sited where pollution is lower than or equal to heavy, require USCDs in the range of 40-50 mm/kV.

Now, with expansion HVDC networks, it may become necessary to build substations even in extremely polluted environments. Choice of voltage levels will then have to consider the feasibility of equipment needs given the applicable pollution requirements. HVDC converter station locations should ideally be sited in areas with the lowest pollution level among all the areas in the project. Alternatively, it may be necessary to opt for indoor solutions to avoid excessive lengths of bushing insulators based on related manufacturing and mechanical constraints.

In principle, lower bushing lengths can be achieved with higher creepage factors but a higher CF would decrease the efficiency of sheds profiles and, theoretically, require higher USCDs. Such choices would have to be verified through testing given that profile parameters under DC reveal that some Creepage Factors can have a much greater effect than under AC.

Conclusions

• Bushings at HVDC converter stations are subjected to different voltage waveshapes depending on location in the substation as well as on the applicable HVDC transmission technology;
• In many situations, the permanent voltage on the bushings is close to pure DC and design is made in accordance with IEC 60815-4;
• In other cases, bushings can experience combined voltages, i.e. AC, DC, and pulsating components, whose shape appears closer to an oscillating than to a direct voltage (pending additional investigation). Conservative design is then made with reference to the DC specification. Adoption of AC voltage as an equivalent voltage for design and testing (as suggested by tests on short insulators), could become a possible future scenario pending further research involving larger, more representative samples;
• High values of USCD are needed for HVDC sites in high and very high pollution environments. This favours use of composite insulator housings and/or indoor installation;
• Widespread growth of HVDC networks may create the need to build new converter stations, even in more extreme environments. Therefore, voltage levels and installation solutions will both have to consider all the limitations linked to design under pollution.

References
[1] IEC/IEEE 65700-19-03, «Bushings fro DC application,» Draft.
[2] «Sofia Offshore Wind Farm,» [Online]. Available: https://sofiawindfarm.com/.
[3] P. Cardano, A. Pigini, M. Sehovac, G. Testin, P. Valvassori, «Converter Transformer Bushing external insulation Design,» in ISH Congress, 2017.
[4] GE Grid Solutions, «The SouthWest Link Transmitting Power and Controlling Voltage with HVDC in Sweden,» [Online].
[5] IEC TS 60815-1, “Selection and dimensioning of high-voltage insulators intended for use in polluted conditions – Part 1: Definitions, information and general principles,” 2008.
[6] IEC TS 60815-2, “Selection and dimensioning of high-voltage insulators intended for use in polluted conditions .Part 2: Ceramic and glass insulators for a.c. systems,” 2008.
[7] IEC TS 60815-3, «Selection and dimensioning of high voltage insulators for use in polluted conditions -Part 3. Polymer insulators for AC systems,» 2008.
[8] Birender Singh Thind, Ajith John Thomas, C C Reddy, «Effect of Voltage Waveform of HVDC Converter Transformer on Lifetime Charachteristics,» in IEEE, 2020.
[9] IEC 60071-12, «Insulation co-ordination – Part 12: Application guidelines for LCC HVDC converter stations,» 2022.
[10] J. Knauel, A. Wagner, R. Puffer, J.M. Seifert, S. Liu, M. Brueckner, B. Rusek, S. Steevens, A. Gravelmann, K. Kleinekorte, «Behaviour of insulators under hybrid electrical AC/DC field stress,» in CIGRE General Session papwe D1_101:_2014, 2014.
[11] A.Wagner, J. Knauel, R. Puffer, J.M. Seifert, M. Brueckner, B. Rusek, S. Steevens, K. Kleinekorte, «Performance of polymeric insulators in hybrid AC/DCoverhead lines under polluted conditions,» in Cigre general session paper D1-112, 2016.
[12] IEC TS 60815-4, “Selection and dimensioning of high-voltage insulators intended for use in polluted conditions.Part 4: Insulators for d.c. systems,” 2016.
[13] A.Pigini, R. Cortina e M. Marzinotto, «Estimating DC pollution requirements: comparison of simplified IEC approach and statistical approach,» in INMR World Congress, 2023.
[14] Y. Solovyev, L. Arevalo, A. Holmberg, D. Gustavsson, «Operational Experience with Composite Insulators at HVDC Stations,» in INMR Congress, 2022.
[15] A. Pigini, «Pollution Design & Testing: Unresolved Issues,» in INMR Congress, 2022.
[16] Working Group C4.303, «Tecnnical Brochure 518 Outdoor Insulation in Polluted Conditions: Guidelines for Selecting and Dimensioning. Part 2: The DC Case,» Cigrè, 2012.

The post Pollution Design of HVDC/UHVDC Outdoor Bushings appeared first on INMR.

This lecture discusses measures for improving lightning performance of transmission lines, based on experience acquired facing the challenge of improving performance of numerous transmission lines in South America, installed in a variety of distinct service environments.

The post Techniques to Improve Lightning Performance of Transmission Lines (Video) appeared first on INMR.

Contamination is a dominant factor for dimensioning outdoor insulators, especially for AC in medium/heavy polluted environments and for all polluted environments in DC. Uncertainty on site contamination severity therefore hampers proper insulator selection and design.

The post Contamination Maps Toward Outdoor Insulation Coordination (Video) appeared first on INMR.

The first transmission lines in Venezuela went into commercial operation in early 1969 and were built using glass and porcelain insulators. Application of polymeric insulators at 400 kV began in 1998 and by the time of this incident they were installed on more than 2500 towers along 980 kilometers of lines, representing about 23% of the country’s entire transmission system. The failure due to brittle fracture described below documented the factors that contributed to this incident considering: period in service, failures of materials, absence of key accessories such as corona rings as well as external factors and environmental pollution that over time can reduce insulator life expectancy.

Guangzhou MPC Power International Co. Ltd.

China

ASAsoft ® (Canada) Inc.

Canada

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On November 12, 2016 at 10:20 am, substation maintenance personnel reported to the Regional Control Center a loud noise in dead-end tower No. 4. It was also reported that an insulator was broken and detached. Immediately, Transmission Line Maintenance personnel moved to the site and found that an insulator that serves as the retention element between phases A and C was broken and detached at one of its ends. Fortunately, the conductor had not fallen since it was in a double chain arrangement. Initially, the insulator was inspected using binoculars, De-energization of the line was requested because significant damage was detected in the insulator bar that was supporting the mechanical load of the four conductors, as shown below. It can be seen that the failed insulator is supporting, in parallel, the mechanical traction exerted by the conductors of phases A and C. Consequently, the double polymeric insulator arrangement is operating at 400 kV phase-phase.

Tower No. 4 is a special tower where the inversion or rotation of phase A and C is carried out to obtain the correct phase sequence for its entry into the arrival Substation. The following figure shows the arrangement and scheme by which phases are rotated.

To assess cause of the failure, a photo record of the status of each insulator was made:

1. It was determined that all the insulators installed in Tower No. 4 had corona rings installed at both energized end and at tower end, except for the arrangement of double insulators that electrically separates phases A and C;

2. The insulator next to the one that had failed was in a critical state, with considerable loss of its polymeric cover as well as serious damage to the initial part of the fiberglass rod and pitting on the surface of hardware. Nevertheless, this insulator managed to withstand the mechanical tension of the conductors, calculated at 5.2 tons.

3. The insulator that had failed by brittle fracture was carefully disassembled and transferred to a laboratory where a scanning electron microscopy test could be performed. Several detached skirts were found on the ground.

• In both cases of failures since 2015, the polymeric insulators were manufactured by reputable suppliers in Germany and the United States.

• In the case of the failed insulator on the Caruachi – Macagua Transmission Line, there were several questions to find the technical explanation, e.g. the insulator located next to the fault was exposed to the same conditions of electric field and corona effects yet did not experience brittle fracture even though it had to endure the same mechanical moment when the other insulator failed and also supported the mechanical load of four conductors. Also, why did the damage to the polymeric cover of insulators fixed at the end of phase C not occur in phase A?

EDP Labelec

Portugal

Powertech Labs Inc.

Canada

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Conclusions

1. With this case, it is shown that, in the case of 400 kV transmission lines, it is extremely important that polymeric insulators have corona rings installed at the energized end – whether these are in suspension or dead-end towers. This is due to reduced life expectancy of a period not exceeding 14 years, from damage caused by corona in the area surrounding the terminal fittings. High electric field results in release of nitric acid that progressively destroys the silicone rubber until the fiberglass core rod becomes exposed to the environment. This then allows entry of water with either a ‘flashunder’ or brittle fracture failure. It is important to note that the fault that occurred in this particular insulator was not due to a manufacturing defect but rather caused by absence of the corona ring, which was not installed during the line’s construction stage.

2. It is recommended to apply UV corona inspection technology in the maintenance policies of public utilities. This condition-based monitoring tool represents a powerful means to detect advanced root cause failures. It also allows active monitoring the condition of components both on transmission lines and in high and extra high voltage substations during normal service. Depending on number and length of lines being operated, it is vital to establish an annual inspection frequency, at the least.

3. It is recommended that when power companies select polymeric insulators for new line projects, they include among their construction specifications, installation of corona rings, designed and supplied by the insulator manufacturer. This is to standardize and regulate electric field at the energized end and avoid exposing insulators to a phenomenon not visible or detectable by simple visual inspection. It is also recommended that, during the assembly stage, the Construction Inspector verify installation of each and every corona ring and that a line is not energized until installation of all these elements has been completed.

4. Another recommendation is that power companies include in their specifications for polymeric insulators a Vibration Test for sets of fittings, insulators and corona rings. This would be both for suspension and dead-end tower arrangements on all lines with average span length greater than 300 m and especially if there are two or more conductors per phase. This is to ensure that corona rings are not loosened as a result of conductor vibration or because they have not been properly installed.

The post Lessons from Brittle Fracture Failure appeared first on INMR.

This edited past contribution to INMR by Marco Nosilati and Davide Momesso of GE Vernova Grid Solutions in Italy, in co-operation with independent expert, Alberto Pigini, analyzed the technical parameters for optimized selection of post insulators, with focus on EHV and UHV disconnectors.

An insulator is defined as: “a device intended for electrical insulation and mechanical fixing of equipment or conductors which are subject to electric potential differences”. This is a highly generalized definition inasmuch as there are many types of post insulators used at substations and converter stations, depending on application, e.g. bus supports smoothing reactor supports, switchgear, busbars, etc. A disconnector is “a mechanical switching device which provides, in the open position, an isolating distance in accordance with specified requirements”. The requirements to be respected for disconnector devices in open-air applications are many but can be divided into three main classes:

• Functional & Electrical Requirements

The main function of disconnector is to guarantee safety. In the open condition, it therefore has to grant a visible and reliable open gap; in a closed condition, it must withstand normal and fault current without interruption or abnormal unsafe situations. A disconnector also has to be designed to avoid discharges across the open-air gap and to earth.

• Mechanical Requirements

From the mechanical point of view, in addition to its own operating loads (weight, operational requirements), the disconnector also has to bear external loads. On UHV equipment, the most severe of these is earthquake. A highly precise design must therefore be achieved if there are seismic requirements. Other loads to also be considered are short-circuit, high wind and terminal loads.

• Environmental Requirements

Being exposed to open air, disconnectors have to withstand all possible environmental factors, including severe ice (important since this can completely change performance of insulators) and heavy rain (which enhances discharge risk). Above all is impact of pollution, which is a key dimensioning factor for insulators and can lead to discharge to earth.

Since all these requirements link closely to insulator performance, post insulators are one of the most important components of a disconnector. At the same time, additional requirements link to displacement under load in service, meaning that disconnectors have one more critical issue to deal with compared to other equipment, namely movement of the mechanical parts necessary for opening and closing. As such, a certain level of rigidity is necessary for proper function of this equipment.

There is a general goal in the electricity supply industry of achieving compact, cost-effective open-air substations. Station post insulator technology can contribute to this goal by limiting necessary arcing distances for busbars, disconnectors and other apparatus. This can be achieved by optimizing post insulator design through selecting the most suitable materials, improving mechanical strength and stiffness, reducing number of stacks and intermediate flanges as well as optimizing shed profile and creepage factor. In regard to UHV applications, the main challenge for post insulators relates to height, particularly since the pollution environment often requires long creepage distances. Mechanical requirements from bending and torsion loads only serve to make this challenge more complex and can also significantly increase the difficulty of manufacturing such units.

PFISTERER

Germany

Guangzhou MPC Power International Co. Ltd.

China

See more suppliers of Support Insulators for Substations

Comparison of Alternative Solutions

There are basically 5 different options when it comes to post insulators: porcelain post insulators; porcelain post insulators with an RTV coating applied at the supplier’s factory; hybrid units consisting of a porcelain core onto which silicone rubber sheds are mounted; solid core composite post insulators; and gas-filled hollow core composite insulators. Every type has its relative advantages and disadvantages and, as such, it is informative to provide a qualitative comparison of the different designs. Unfortunately, accurate quantitative data cannot be provided in each case since there are many influencing factors – from technical performance to economic considerations that depend on manufacturer, relative cost, country of application, etc. In order to perform qualitative comparison, ratings have been assigned to factors that influence choice of insulator and the resulting Tables obtained for both EHV and UHV classes shows that choice among the different insulator options depends on disconnector voltage rating. In each Table, a score from ‘1’ to ‘5’ has been assigned, where ‘1’ means that the characteristic is poor while ‘5’ means it is a point of strength and highlighted in green.

From Tables 1 & 2, and also based on GE experience, it can be said that solid core porcelain is still the preferred and most common choice for post insulators for EHV disconnectors, given the major economic benefit as well as technical reliability of this solution. Most porcelain station post insulators are still based on traditional and relatively low cost stacking technology, whereby insulators of 1 to 2 m arcing distance are stacked in an assembly to reach the desired arcing distance across the EHV to UHV range. However, more advanced porcelain solutions are now also available that allow single unit insulators of several meters to be produced along with optimized profiles that see reduced shed thickness and tip radius. A main issue in this regard is that wide core dimensions are not easy to produce and require special technical skill. For example, manufacture of insulators with wider diameters can result in differential cooling after the molding process, causing cracks. In addition, other parameters such as quality of the porcelain body and cement also have to be considered.

The composite solution permits insulators of whatever length is necessary without flanges while also offering well-known advantages such as low weight and good performance under pollution and seismic conditions. The main disadvantage is higher cost compared to the standard solid core porcelain solution. This limits application at lower transmission voltages. By contrast, hollow core composite insulators, especially those filled with an eco-friendly gas that is properly monitored, seem to be the preferred solution for UHV disconnectors due mainly to the possibility of increased diameter without significant impact on either weight or cost-effectiveness. Of course, such a solution still has to be properly designed to comply with specific mechanical constraints (e.g. minimizing deflection at the top for disconnector applications) and also rigorously tested from the sealing and monitoring points of view. Nonetheless, it must be noted that there is still relatively limited service experience for composite hollow core insulators at UHV.

Porcelain post insulators with an RTV coating applied at the factory of the supplier could represent a good solution for UHV due to excellent pollution performance but comes with the disadvantage of periodic maintenance of the coating, usually guaranteed only for about 10 years. The hybrid solution with porcelain core and silicone shed housing shares advantages and disadvantages of the above solutions. One of its drawbacks is much higher cost with respect to traditional porcelain stacking technology while not offering a significant benefit in terms of weight reduction (i.e. only about 20%). Indeed, cost is a key driver in choice of insulator when it comes to disconnectors given that these account for a significant percentage of overall cost, i.e. up to 30% for EHV and up to 70% for UHV disconnectors. Of course, insulator cost can vary widely depending on supplier location, manufacturing process and technology used.

Mechanical Sizing: Optimization & Constraints

Many aspects have to be considered during mechanical sizing of disconnectors. In regard to the insulators, the key parameters to be taken into account are rigidity, which influences displacement due to load, and resistance, i.e. capability to withstand a load without break. First of all, a disconnector has to ensure electrical continuity, even during seismic events or short-circuits. It also has to operate properly under rated static terminal loads that represent the impact of high-voltage conductors or busbars linked to the disconnector, as recommended by specifications or in the standards. Considering the same diameter, porcelain insulators are more rigid than composite types, with a higher material Young’s modulus by up to 60%. The latter can be subject to high displacement and therefore an accurate design has to be realized whenever composite insulators are selected. It should be noted at the same time that composite insulator technology these days allows these to be offered with very large diameters and this helps compensate partially for the inherent difference in rigidity versus porcelain.

Measurement of displacement under load is an important test, even if it is classified a ‘special test’ and rigidity gains even more importance for UHV projects where insulators are longer than at EHV (see Fig. 1). For example, GE usually performs a bending test along with measurement of displacement under load for its UHV projects. Figs. 2 and 3 show mechanical tests on a hollow core composite insulator and on porcelain.

For UHV projects, with high rated static terminal loads or where there are high seismic requirements, GE has adopted two main solutions: more insulators in parallel, as shown in Fig. 4 at right or only a single composite hollow core insulator, as shown in Fig. 4 at left. Since composite hollow core insulators do not have any technical issues, wide diameters can be obtained along with high rigidity.

In regard to the issue of resistance, the most severe mechanical load is usually due to earthquake. Worldwide, there are many seismic standards and technical specifications for disconnectors but the most common are IEEE 693, IEC 62271-300 and ETG-1.020. Unfortunately, these have different qualification procedures and cannot easily be compared. For design purposes, they provide different Required Response Spectra and load combinations. For example, considering X as the longitudinal axis, Y as the transverse axis and Z as the vertical axis:

• IEC 62271-300 requires combining seismic load, the 70% rated static terminal load, the internal pressure of the insulator (if any) and 10 m/s speed wind. Then, it requires to separately combine the loads in the X – Z and Y – Z planes (with the SRSS method) in order to determine maximum stress. The minimum safety factor the insulators must have is at least 1;

• IEEE 693 considers seismic load only, 100% in X and Y directions and 80% in direction Z. The combination (with the SRSS method) has to provide a minimum safety factor equal to 2;

• ETG-1.020 requires combining seismic, rated static terminal load, short-circuit, wind and short-circuit loads, with minimum safety factor of 2.

In seismic design, the goal is to obtain light but rigid disconnectors for the following reasons:

• the lower the mass, the less the seismic load;

• equipment with high rigidity and low mass has high natural frequencies. This way, more vibrational modes could be excited at low loads – outside the maximum peak of the required response spectrum (RRS).

Conversely to these design aims, GE has found in its numerical modeling that an insulator with less rigidity is also subjected to lower stress (see Fig. 5). Indeed, more energy is dispersed due to displacement, thereby enhancing overall damping. As such, wherever possible, real measurements from deflection under load test are used to properly characterize the dynamic behavior of equipment with the aim of trying to balance these two factors: enhance overall rigidity of equipment so as to have vibrational modes outside the maximum peak of the RRS. But if this is not possible, another approach could be to use fewer rigid insulators, which are usually the most critical points.

Given this dynamic analysis, GE considers shake-table tests to be important, especially if high seismic levels are required or for UHV projects. Testing is the only way to evaluate the real seismic performance of a piece of equipment under certain conditions. In FEM analysis, by contrast, it is difficult to properly model all components and some therefore have to be simplified. An example of this philosophy in practice was the shake-table test conducted at 0.4g on SPOL ±800 kV for the Dianxibei Project (see Fig. 6).

Low weight is fundamental to every disconnector subject to seismic events and becomes even more important for UHV equipment where many meters of length and wide bottom diameters are necessary. Composite insulators are much lighter than porcelain and therefore provide the best dynamic behavior. Fig. 7 provides ratios between cantilever and weight [N/kg] at different BIL values for both composite hollow core and porcelain insulators and shows that composite hollow core insulators provide better performance (i.e. they can withstand higher load for every kg).

As stated, composite hollow core insulators are usually used for UHV applications. At lower voltages, porcelain often provides acceptable seismic performance while also being less costly. During the mechanical design and validation process, testing is regarded as an especially important aspect when it comes to the above seismic tests as well as in-depth verification of insulator performance (see Figs. 2 & 3). Such tests are performed according to IEC 60168 and also follow a dedicated procedure prepared by GE that is even more severe both for porcelain and composite insulator types in order to ensure the highest possible quality. For porcelain, for example, all type tests from IEC 60168 are performed along with some testing to breakage so as to establish the real resistance. In regard to composite insulators, GE conducts a validation test campaign, especially for UHV, which involves thermal cycle testing (i.e. at different temperatures) and mechanical bending cycles with the goal of simulating a fast ageing test of the material (see Figs. 8a & b).

Indeed, it has been found that temperature can greatly influence properties of composite hollow core insulators but does not considerably impact porcelain. Hot environments can:

• Accelerate material ageing

• Composite materials are normally subject to this phenomenon,  accelerated by high temperature, that causes increased loss in insulator performance over time;

• Decrease mechanical properties

• High temperatures cause a decrease in rigidity, especially resistance of the insulator

The fast ageing test on specimens is useful to determine what maximum mechanical load can be applied to a composite insulator given a certain ambient temperature.

Electrical Sizing: Optimization & Constraints

Dimensioning of insulation on EHV and UHV AC disconnectors towards ground and the longitudinal gap is generally dominated by switching overvoltage. This is simulated in a test laboratory by standard switching impulses (250/2500µS). In particular, dimensioning of insulation towards ground is also dominated by switching overvoltages, e.g. under rain conditions, up to conditions of high pollution using insulators with a relatively limited creepage factor (see Fig. 9). SI continues to dominate a project even under more severe pollution conditions using insulators with a larger creepage factor, as foreseen in IEC Technical Specification 60815, or, if necessary, using composite insulators.

Optimal design of post insulators from the contamination point of view has been established based on systematic pollution tests, also taking into account comparative performance at different altitudes (see different test set-ups in Fig. 10). High altitude tests have indicated USCD values higher than those obtained at sea level and confirmed the need to correct RUSCD for altitude. For example, at an altitude of 3500 m withstand salinity is estimated at only about one third that at sea level. Use of composite insulators may therefore be necessary in very heavy and extreme pollution environments or for other reasons, such as to meet seismic requirements.

Systematic SI tests were conducted in GE’s test laboratory as well as at major laboratories worldwide to investigate the SI performance of disconnectors of different types and namely:

• horizontal disconnectors, with a single gap;
• horizontal disconnectors with intermediate electrode;
• vertical disconnectors.

Fig. 11 shows examples of disconnectors under test.

Optimization of SI insulator design was made referring to experimental results and calculations as well as by taking into account available experience on air gap performance developed within CIGRE and, in particular, experience with combined SI and AC voltages (bias tests as foreseen for AC disconnectors) The main conclusion of these investigations was that, given stress values in IEC 62271-1, the distance required between open contacts is generally lower than that required to ground. A conservative design is therefore realized by assuming the same clearance to ground as between open contacts (longitudinal insulation).

DC Applications

Since influence of DC on SI strength is negligible, design can be made as for AC by applying SI only. Fig. 12 shows examples of configurations under SI testing. Due to required insulation to ground, multi-column insulators may be necessary for the highest system voltages, as in the UHV range.

Also, insulation between terminals is verified by applying SI to only one of the terminals. This is because, unlike in AC, no conditions in service can lead to high DC voltage stress in the second terminal. For DC, distance between terminals can be significantly lower than the distance to ground (generally dominated by pollution). By way of preliminary analysis, Fig. 13 offers a qualitative evaluation and comparison of the phase-to-ground pollution requirements and SI requirements (under rain). For qualitative comparison purposes, USCDs were associated to pollution classes, as for AC, taking into account the design curves in IEC 60815 (see Table 3). Maximum applicable creepage factor (i.e. ratio between creepage distance and arcing distance) is assumed to be 4 for ceramic insulators and 4.5 for composite types, in agreement with this Technical Specification.

Fig. 13 confirms that, in the case of porcelain, pollution generally dominates phase-to-ground design under most pollution conditions, even when considering high insulator creepage factors. Very long insulator sets may therefore be necessary with porcelain insulators, making this solution impractical or in some situations even impossible, i.e. heavy pollution and high system voltage. More reasonable heights would be required in the case of hydrophobicity transfer material (HTM) insulators such as RTV coated porcelain, hybrid insulators or composite types, the latter being the preferred choice if there are also strict seismic requirements. Indeed, use of HTM insulators can reduce creepage distance by up to 30% (see Eqs. 1 and 2, which consider an ESDD of 0.12 mg/cm²).

As mentioned, the above gives only preliminary indications. More precise indications for pollution can be derived by results of ad hoc testing. Indeed, systematic laboratory tests with solid layer and salt fog were carried out to select the optimal composite insulator profile and sizing with special attention to harsh environments (see Figs. 14, 15 & 16).

Extreme Environmental Conditions

Aside from pollution, other environmental conditions also have to be taken into account, including severe icing or heavy rain. In cold climates, for example, insulator performance can be affected under severe ice conditions. The design process followed in one such study, presented during CIGRE general Session in 2018, was conservative and based on limited available data. This research determined that insulation performance depends on three main environmental parameters:

• ice load thickness;
• conductivity of the water that froze into ice;
• presence of pollution on the insulator surface.

Insulation performance also depends on three main geometrical parameters:

• arcing distance;
• external diameter of the insulator;
• insulator inclination.

Once the influence of all these parameters has been established, the dielectric performance of an insulator under heavy ice has a linear relationship to length. As such, preliminary design was performed by calculating parameter ‘E, which is the withstand voltage per unit of insulator length. Numerous dielectric tests were then performed to verify insulation performance (see Fig. 15).

In tropical climates, heavy rain can influence insulating performance. Some of the principal conclusions of past research in this area include:

• Large station insulators, especially in the vertical position, can be critical under heavy rain conditions (according to service experience);
• In general, average rain parameters can be considered adequate given that the highest overvoltage values have only low probability of occurring at the same time as the most severe rain. If extreme environments are concerned (e.g. high rain rate and/or high rain conductivity), further analysis may be necessary;
• Under severe rain conditions, greater distance between sheds is advisable.

Summary & Conclusions

Optimization of post insulators for substation applications from the mechanical and electrical points of view depends on many factors and also on environmental conditions such as pollution, heavy icing and high temperatures.

Considering disconnectors, applications requirements include the capability to maintain electrical continuity (i.e. avoiding separation of main contacts) as well as ensuring proper operation. As such, insulators must have a certain rigidity to avoid high displacements at terminals given that displacement under load is a key-driver in design. If a stand-alone supporting insulator is considered, there is less need for rigidity and a more flexible insulator can be used. This reduces its stress while also enhancing seismic performance, taking into account the values of modal frequencies and of RRS peak limits. Another key element in insulator selection is cost effectiveness.

For EHV, the most common insulator type is porcelain, which is also the least costly. At UHV, however, porcelain is often no longer the most cost-effective solution and, as with HVDC applications requiring very long creepage distance, hollow core composite insulators become competitive with other types. Similarly, composite insulators can be adopted under severe service conditions in terms of pollution and seismic conditions. In fact, creepage distance requirements in such cases would make porcelain insulators too high and weak from the mechanical point of view – especially under seismic loads.

At the same time, it should be noted that composite insulators, both hollow and solid core, could face possible additional issues such as risk of premature ageing of the silicone material or loss of hydrophobicity over the expected service life. Moreover, since hollow core composite insulators need to be filled with gas or foam, GE has developed a patented eco-friendly nitrogen solution for its HVDC AIS disconnectors. A gas leak-detecting device, as already being provided for this equipment, is strongly recommended even if the insulator is sealed so as to best monitor disconnector status over its lifetime and perform predictive maintenance.

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