Innovative Designs of Porcelain Long Rod Insulator Strings for HVDC Overhead Liness
by Jens Seifert

Electrical performance of porcelain long rods can be enhanced by applying RTV coatings, which give the same performance to other types of insulators and especially so for slim high creepage designs with high form factors.

The post Innovative Designs of Porcelain Long Rod Insulator Strings for HVDC Overhead Lines (Video) appeared first on .

Experience in On-Site Commissioning Testing of HV Cable Systems
by Bas Verhoeven and Antonio Boccuni

A comprehensive statistical analysis has been conducted using a database that contains detailed records from hundreds of commissioning tests. Results reveal insightful trends when examining the number of tests performed annually, categorized by voltage class and circuit length.

The post Experience in On-Site Commissioning Testing of HV Cable Systems (Video) appeared first on .

Wenzhou Yikun Electric

China

EMCO Industries

Pakistan

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Depending on magnitude of the voltage that occurs, a basic distinction can be made between two working areas of a MO arrester. In the case of continuous voltages and temporary overvoltages, the device must guarantee operational stability, i.e. it must not be overloaded. In the second working range, the protection level of the arrester limits any overvoltages that occur. This is illustrated in Fig. 2.

In addition to the voltages that occur, the protective characteristics of the arrester, which only apply at its installation location, must also be taken into account. For example, there is a reduction in the protective effect with increasing distance due to traveling wave phenomena. Representative overvoltages on any equipment to be protected can be estimated simply by considering several parameters: lightning protection level of the arrester; steepness of the incoming lightning overvoltage; and transit time of the lightning overvoltage across the sum of the distances.

Considerations in regard to acceptable error rate as well as possible inaccuracies in the statistical distribution and calculation of an arrester’s protective area lead to coordination of withstand voltages. Required withstand voltages for safe operation are obtained using a safety factor intended to compensate for any deviations from the conditions during testing to the actual conditions in the network. Conversion to the test voltages and selection of the next higher standard value ultimately lead to rated voltages, which together result in the rated insulation level of a system. Fig. 3, for example, shows the basic structure of metal-oxide arresters based on a GIS arrester with a built-in separator. A disconnect device is helpful because the arrester is to be disconnected during on-site HV testing. To ensure functionality, all arresters are subjected to extensive type tests in accordance with IEC 60099-4, Ed. 3.0: Surge arresters – Part 4: Metal-oxide surge arresters without gaps for a.c. systems.

Insulation Coordination

Insulation coordination is one of the essential design criteria for electrical energy systems and their components since it determines both reliability and availability. The main task in this regard is determining the coordination withstand voltage, which must take into detailed account all voltage stresses:

Continuous operating voltage;
Intermittent overvoltages;
Slowly increasing overvoltages;
Rapidly rising overvoltages;
Overvoltages that rise very quickly (e.g. from disconnector operation);
DC voltages.

Rapidly rising (transient) overvoltages, in particular lightning overvoltages, are of the utmost importance in the basic design of switchgear and their components. The corresponding coordination withstand voltage can be determined using deterministic or statistical methods, with the former being used most often. This method uses withstand voltages for which operational experience is available and error rates are known. In this context, limitation of overvoltages using arresters plays a role.

For example, Fig. 4 qualitatively shows reduction in overvoltage as a result of a lightning strike on a conductor by positioning surge arresters (SA1 & SA2) at different points in a GIS. When gas-insulated switching devices are involved, overvoltages that rise very quickly must be taken into account. When operating disonnectors, overvoltages are usually no greater than 2.0 p.u. (1 p.u. = √2 × Us / √3), although overvoltages of 2.5 p.u sometimes occur and, in rare cases, even 3.0 p.u. As a result, levels of the rapidly rising overvoltages are significantly lower than the lightning impulse voltage level and are therefore less critical. The very rapidly increasing overvoltages in the UHV range in the area of the disconnector itself play a more significant role.

When determining coordination withstand voltage, influencing factors that reduce insulation strength during the service life of a system must be taken into account. As discussed, this is done with a safety factor that takes into account effects of ageing, possible variances in manufacturing, inaccuracies in withstand voltages and other unknowns. A safety factor of 1.15 is used for the internal insulation. Environmental influences may also have to be taken into account and a safety factor starting from 1.05 applies to the outer insulation. After determining required withstand voltages, the operator can specify required insulation level. In general, reference is made to rated insulation levels based on relevant regulations, which contain different withstand voltages and test levels for each voltage.

Application Examples

1. Cost Reduction for Rail Electrification

Most railway lines in industrial Europe were built at the beginning of the 20th century and diesel locomotives are still used in some countries. While many routes in Germany, for example, have now been electrified, bridges and underpasses pose a recurring problem since they are often too low to maintain so-called ‘minimum electrical distances’, i.e. distance between electrical lines and structure. If too low, lightning strikes might cause a flashover resulting in damage to the system and infrastructure.

For example, when the Danish State Railways decided to electrify their entire network in 2015, the tender required a supplier that could also bring an innovative solution for the catenary given the numerous low bridges along rail lines. Raising a bridge and roads would be costly and in many cases not even possible due to opposition by city planning authorities. In order to meet the stringent requirements of this project, medium-voltage arresters were developed using large metal oxide resistors from the high voltage range. This enabled insulation coordination and reduced distances to be implemented.

This approach of shorter distances while maintaining appropriate protection has now been adopted in the corresponding railway standard (EN 50124) revised in April 2020. This reduces lightning overvoltages to a level no longer dangerous for existing bridges and tunnels. For example, the normal distance of 27 cm for 25 kV system voltage on the overhead line could be reduced to only 15 cm with the help of an arrester. For many bridges along the Danish route this was the greatest possible distance from structures. With application of the new MO arrester, tracks no longer needed to be lowered nor bridges or overpasses raised. Arresters in this application are mounted on each side of the structure and connected to the catenary via the carrying cable (see Fig. 5). The financial outlay was relatively low considering the savings.

2. Concept of Sacrificial Arresters at 16.7 Hz Rail Electrification Overhead Lines

For reasons of cost and space, 110 kV railway power lines and 380 kV overhead lines are often installed on common masts. In the event of any short circuit between these systems, the railway power supply system can incur serious damage since the 380 kV overhead line network protection only recognizes the fault once serious damage has already occurred to the 16.7 Hz/110 kV traction network. One way to prevent this risk is by using so-called sacrificial arresters on the traction network. In the event of a fault, these fail quickly and are deliberately sacrificed to protect other equipment or the entire network. Loss of an arrester in this type of situation is acceptable. The arrester housing in this application is dimensioned such that it can carry the short circuit current for the required protection response time of approximately 2 seconds (see Fig. 6).

3. High Cooling Arrester (HCA) for HVDC Converter Stations

High cooling arresters (HCA) have been specifically developed to protect thyristor valves at HVDC converter stations and are characterized by an approximately 10% lower protection level and improved heat dissipation behavior than conventional arresters with housings. Here, the metal-oxide varistors (MOV) of the HCA are operated for the applied equivalent continuous voltage in the upper leakage current range of the current-voltage characteristic, which leads to increased power consumption. Since good heat dissipation to the environment is required to ensure thermal stability, HCAs have no housing and are equipped with additional cooling elements. To protect the MOVs, these are fitted with silicone screen covers with the HCA being an indoor only unit. Fig. 7 shows the lower portion of an HCA arrester with cooling elements and shielded MOVs.

Under certain circumstances, the approximately 10% lower protection level of the HCA compared to a normally housed arrester can enable the number of series-connected thyristors to be reduced by the same order of magnitude and thereby contribute to significant cost savings.

4. Line Compaction

Application of line surge arresters (LSAs) has been a proven solution worldwide, especially in regions with high atmospheric lightning activity. LSAs are used to avoid brief interruptions in overhead lines due to rapidly increasing overvoltages. The two variants are the so-called NGLAs (non-gapped line arresters) without a spark gap and EGLAs (externally gapped line arresters) with an external serial spark gap. The EGLA has the advantage of lighter construction but the spark gap must be dimensioned such that it responds reliably to rapidly increasing overvoltages so as to prevent the insulator from flashing over. Fig. 8 shows an example of a 245 kV EGLA installation.

Although the effectiveness of line arresters has been proven in practical applications, they are still rarely taken into account when designing new overhead lines.

Another option when using line arresters is reducing insulation distances. With their application, distance requirements and thus structure height and width can be significantly reduced, making them far more compact. This immediately reduces environmental impact of a new overhead line projects. Moreover, for existing systems, it becomes possible to also increase the voltage to the next level along the route without having to significantly change either spans or structures. In addition, increasing transmission capacity by increasing amperage can cause related expansion of the conductor, which could fall below required ground clearance. A shortened EGLA chain, including insulators on the overhead line, can counteract such expansion so as to maintain the minimum distances required.

5. Protection at High Altitudes

In the case of switchgear located at high altitudes, atmospheric conditions can lead to correction factors that require a significantly higher insulation level of the high voltage component than would otherwise be normal for that voltage. This can require application of components for the next higher voltage level along with associated higher costs. Targeted use of arresters in these situations can help reduce costs by up to 40%. Arresters in such applications are attached directly to the device being protected. With use of an arrester, any overvoltages that might occur on the device can be kept low enough that standard insulation remains sufficient. This type of application requires detailed calculation of the coordination withstand voltage in accordance with information contained in IEC 60071-2.

6. Switchgear & GIS Interfaces

Global experience with gas-insulated high-voltage switchgear (GIS) shows high operational reliability with low error rate. In fact, numerous systems have reached a service life of more than 50 years without any increase in error rate (see Table 1).

Together with the high reliability of MO arresters, this experience can be used to carry out further system optimization. Lightning overvoltages can only be effective in direct connections to overhead lines and at substations with connected overhead lines. Gas-insulated systems have lower wave resistance than overhead lines and an incoming voltage wave is therefore significantly reduced.

Wave impedance depends on GIS dimensions. The reduced voltage wave travels through the system and is reflected and broken by changes in the characteristic impedance. The reflected wave returns and is reflected and refracted again (see Fig 9). The superimposition of forward and reverse waves builds up different voltage maxima along parts of the system up to a theoretical maximum corresponding to twice the voltage wave arriving from the overhead line. Therefore, effects of traveling waves, including the MO arrester, must be taken into account during system design.

Voltage stress can be reduced by placement of MO arresters. Integrated GIS arresters are especially advantageous in terms of voltage reduction because of lower inductance compared to outdoor arresters. The result is up to 15% lower residual voltages by comparison with outdoor arresters (see Figs. 10 and 11).

Reactive power compensation reactors that may be provided also have a voltage limiting effect, which must be taken into account in overall system optimization. Overall standard lightning impulse withstand voltage (LIWV) of equipment can be reduced using arresters. Table 2 shows the effects, according to IEC 60071-1, for LIWV levels of 1050 kV and 1425 kV using the example of a 420 kV GIS outlet with CO₂-neutral compressed air (i.e. clean air versus SF₆ insulation). There is no doubt that dimension, weight and cost can be significantly reduced with the same reliability with the lower LIWV levels. These advantages increase when compressed air is used as insulating gas instead of SF₆.

Conclusions

High quality metal oxide arresters are essential for the safe operation of today’s AC and DC energy systems. Making smart choices and taking insulation coordination into account allows protection level to be optimized for many electrical system applications, thereby significantly reducing costs.

Reference Literature
[1] H. Ito, N. Uzelac, F. Richter, R. l. Roux, W. Pepper, L. Peng, A. Manim, I. Hategan, „ CIGRE Reliability Survey on Equipment”, A3-201, e-Paris 2020
[2] Volker Hinrichsen: “Metalloxid-Ableiter in Hoch-spannungsnetzen”; www.siemens-energy.com/arrester; 3. Auflage / 2012
[3] IEC 60099-4, Ed. 3.0: Surge arresters – Part 4: Metal-oxide surge arresters without gaps for a.c. systems
[4] IEC 60071-1: Insulation Co-ordination, Part 1: Defi-nition, principals and rules
[5] IEC 60071-2: Insulation Co-ordination, Part 2: Appli-cation Guide
[6] IEC TR 60071-4, Insulation co-ordination – Part 4: Computational guide to insulation co-ordination and modelling of electrical networks
[7] CIGRE WG 15.03: GIS insulation properties in case of VFT and DC stress. CIGRE 15-201, 1996
[8] CIGRE JWG 33/23.12: Insulation co-ordination of GIS: Return of experience, on site tests and diagnostic techniques. ELECTRA No. 176, Feb. 1998, S. 67 – 97
[9] CIGRE WG D1.03, Very Fast Transient Overvoltages (VFTO) in Gas-Insulated UHV Substations, CIGRE technical brochure No.519, 2012
[10] M. Kuschel: Isolationsbemessung von GIS, FGH Se-minar Isolationskoordination, 19. – 20. Februar 2019
[11] IEC 62271-1, High-voltage switchgear and control-gear – Part 1: Common specifications for alternating current switchgear and controlgear
[12] G. Bromley, “Introducing Surge Arrester Technol-ogy” in Rail Engineer, Issue 158, 2017
[13] M. Westenthanner, „Opferableiterkonzept für die Pa-rallelführung von 110-kV-Bahnstromleitungen und 380-kV-Freileitungen“in eb-elektrische Bahnen 2016
[14] R. Göhler, V. Brendler, V. Hinrichsen, J. Shaikh, M. Weyer, M. Giessel, CIGRE A3-112 Arresters with ad-vanced cooling performance for protection of valves in HVDC converters, 2016
[15] B. Robben, M. Jolic, „Reducing Clearances by Inte-gration of Externally Gapped Line Arresters on HV Transmission Lines” in INMR 2019
[16] Siemens Energy Betriebsanleitung, Bestell_Nr. 92800096100a
[17] CIGRE 3rd Survey „Final Report of the 2004 – 2007 International Enquiry on Reliability of High Voltage Equipment, Part 5 – Gas Insulated Switchgear (GIS)” WG A3.06, 10/2012
[18] Felix Goll, Rolf Witzmann: “Lightning Protection of 500-kV DC Gas-Insulated Lines (GIL) With Integrated Surge
[19] O. Völcker, H. Koch, “Insulation co-ordination for gas-insulated transmission lines (GIL),” in Proc. IEEE Power Eng. Soc. Winter Meeting, 2000, vol. 1, pp. 703–711
[20] Cigre JWG 23/21/33-15: “Gas Insulated Transmis-sion Lines (GIL)”, Technical Brochure 218, 2003
[21] E. Kynast, Isolationskoordination und Hochspan-nungstechnik in den UHV-Technologien, Dissertation, TU Graz, 2011 [22] M. Kuschel et al, Entwicklungsstand, Vor-Ort-Erfah-rungen und Ausblick zu SF6-freien Hochspannungs-schaltanlagen, VDE Hochspannungstechnik, 11 / 2020

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Several methods have been proposed as part of the battle to maintain outdoor installations operating without failure under environmental pollution. This edited past contribution to INMR by Dr. Kiriakos Siderakis, invesitgated the problem of pollution maintenance for substations based on extensive experience battling the problem on the Greek island of Crete.

PFISTERER

Germany

EMCO Industries

Pakistan

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High Voltage Substations

The high voltage substation is a node in the transmission system and any outage there typically corresponds to a far more severe impact on a power system than a corresponding incident on a transmission line. Therefore, from the reliability point of view, substation maintenance has considerable importance, which only grows with the corresponding increase in number of connected transmission circuits. Fortunately, as far as pollution is concerned, in the case of substations there are two important advantages compared to dealing with the same problem affecting overhead lines. First, a substation is a geographically concentrated installation and therefore the environmental conditions that affect it tend to be more uniform. Second, most substations are supervised, either locally by personnel or remotely. Consequently, the development of any pollution problem can be detected and suitable remedial measures applied in time. That explains why the incidence of pollution related outages at substations is relatively small compared to transmission lines.

Nevertheless, there are still variables that can complicate any effort to find permanent solutions for substations. One is the fact that there can be a large number of different insulators serving diverse equipment applications such as CTs, VTs, bushings, station posts, arresters, etc.. Each might have different geometries and therefore be subject to different pollution performance and maintenance requirements.

Assessing Pollution During Design Process

In the case of a new substation installation where pollution problems are likely to be a concern, methods and solutions are available to restrict or even eliminate possible negative influence from the environment. Table 1 summarizes the aspects usually considered during the design process.

The first step is selection of insulation parameters and creepage distance. Required values can be determined using IEC 60815, which recommends specific leakage distance based on type and intensity of environmental pollution. Insulator geometry is also important and selection of a suitable profile must aim to take advantage of self-cleaning mechanisms. Otherwise, problems can still be experienced even when the basic leakage distance criterion is satisfied. Such instances, for example, have been experienced on Crete.

Use of composite insulating materials that provide a hydrophobic surface offers improved pollution performance that should be considered as well. But expected service life of these insulators then becomes another factor to consider, especially since replacement cost can be high and availability is another issue. Moreover, even with such materials, the most suitable insulator geometry must still be evaluated.

For example, new silicone post insulators at a 150 kV substation on Crete were monitored after installation using a leakage current measuring system. While it is evident that the insulators demonstrated satisfactory performance, increased activity was recorded whenever there was rain, probably due to their geometry. Fig. 2b shows a typical leakage current waveform demonstrating this effect.

Substation scheme is also an issue impacting maintenance policy against pollution. In Greece, for example, live water washing has not been a realistic option and therefore different supply schemes have had to be available to avoid power interruptions and maintain high reliability levels. The scheme usually implemented to deal with this constraint has utilized multiple bus systems and sectionalizing circuit breakers.

Finally, if expected pollution problems are severe and unavoidable, construction of enclosed substations should be considered. The majority of 150 kV/20 kV substations on Crete are partially enclosed with only the 150 kV side exposed to the outdoor environment. In addition, one particularly problematic 66 kV air-insulated substation was fully enclosed. While in both such cases environmentally induced problems affecting insulators are limited, some control over the atmosphere at enclosed substations remains necessary due to risk of phenomena such as condensation.

One substation scheme that is fully resistant to environmental impact from the start is a GIS installation (i.e. fully enclosed in SF6). While risk of any pollution related problem is virtually eliminated and there is also a saving in space, other issues to consider include maintenance as well as installation costs.

Pollution Maintenance at Existing Substations

In the case of equipment already in-service at substations, the incremental investment to apply the remedial measures outlined in Table 1 can be considerable. Therefore, alternative measures must be found to improve the performance of existing insulation.

The first action usually taken in this regard is cleaning the affected insulators. Table 2 outines different cleaning methods which are then selected based on parameters such as number of insulators to be cleaned, specific pollutants to be removed, possible by-products and corresponding application costs. These methods are made easier since affected insulators are typically located relatively close to one another.

For all different cleaning methods, the key factor is selection of optimum time to clean. This is usually an experience-based parameter that depends on local service conditions. If cleaning is performed earlier than necessary, critical build up of contaminants can still occur within a relatively short time and the basic problem remains. On the other hand, the longer cleaning is delayed, the higher the probability of an outage triggered by pollution.

There is usually considerable cost related to most cleaning procedures, especially if they cannot be applied live. In this case, interruption in supply is required. This corresponds to deterioration in system availability since a portion of the substation is placed out of service. There may also be financial loss since interrupting power supply to a number of consumers may be necessary. It is worth noting that this loss can increase significantly in the case of step-up substations, e.g. if due to supply interruption one or more power units have to be taken out of operation for several hours. One such case was recorded in Crete in the early 2000s when it was required to clean a substation in two parts at least twice each summer. In addition, man-hours required also have to be taken into account, especially considering that insulator cleaning is often performed during hours of low load, i.e. during the night or early morning.

While cleaning insulators is certainly one way to ensure performance under pollution conditions, selection of the optimum cleaning time is critical (since it is a reaction and not a preventive measure) while all associated costs must be calculated, especially if not applied live. For these reasons, a more advanced approach aims to improve the corresponding surface performance of insulators under pollution.

Different types of insulator coatings exist, however the most common types are silicone grease and RTV silicone coatings. Their use constitutes a preventive method since they can be applied at a time convenient for the utility. Over their operational lifetime, such coatings are capable of suppressing the impact of pollution and eliminating any related insulation problems. In both cases, suppression of leakage current is achieved by providing a water repellant surface that does not permit formation of a surface film of conductive contaminants. The main difference between the two lies in method employed to maintain water repellency, even as contaminants deposit on the surface

In the case of silicone grease, all deposited contamination becomes encapsulated within the material’s volume and, as a result, the insulator surface remains clean. This process, however, suggests that there is a saturation point where no additional contaminants can be encapsulated. This point marks the end of its effective service life and the material must then be removed. Otherwise, there is risk of even worse pollution performance than an insulator without grease. On Crete, for example, the average life of silicone grease coatings has been found to be only about 6 months and they must be applied and then removed twice each year. This has limited application mainly to critical equipment.

A water repellant surface is also the primary feature of RTV silicone coatings. However, unlike greases, there is no encapsulation feature but rather a hydrophobicity transfer capability that is sufficient to change the initial hydrophilic behavior of the deposited contamination film to hydrophobic. As a result, although deposited contaminants remain (i.e. with no encapsulation), the surface continues to be hydrophobic. This offers considerable improvement versus grease since accumulated contamination is still exposed to various cleaning mechanisms such as rain and no level of saturation is reached. In addition, service life in some cases can easily exceed 10 years. RTV coatings should therefore be considered as an efficient pollution countermeasure at most substations. They can be applied at a time convenient for the utility on any insulator, regardless of material, type of equipment and shed geometry. In the case of Crete, for example, it was found that the total cost for application of all the RTV coatings in use was still less than the corresponding cost of washing at the most problematic substation over a period of only three years.

Of course, possible drawbacks that must also be considered. These include ageing, maintenance and finding the optimum time for replacement along with the corresponding cost (labor and materials). Still, their preventive features and the possibility of large-scale application are considerable advantages that distinguish this maintenance alternative from others. Unfortunately, coatings cannot fully counterbalance lack of proper creepage distance on inappropriately dimensioned insulators, given the pollution environment.

If specific leakage distance is insufficient, use of elastomeric creepage extenders might be obligatory. As with RTV coatings, extenders can be applied on any insulator type but must be specifically designed for the unit’s geometry – something that limits large-scale application and also increases application costs. Therefore, it is a method usually adopted for severe conditions or when the methods mentioned above are not sufficient used alone.

Application of RTV Coatings at Substations on Crete

The first application of RTV coatings on Crete began in 1998 at the Linoperamata 150 kV step-up substation, which became fully coated a few years later. Other of the island’s substations have since been coated and thousands of kg of coatings are already in service at 66 kV and 150 kV substations on the islands of Crete and Rhodes. Since initial application, surface activity due to pollution has been substantially suppressed and no flashovers occurred, even though all washing was suspended on coated insulators. The application can therefore be considered a success by any measure.

However, with coatings that exceed a life of 5 years and often closer to 10, there have been concerns how best to evaluate the material’s continued reliability and then decide on any maintenance actions. Under normal service conditions, evaluation of coatings has been based mainly on empirical observations, such as surface discharges, noise and visual effects from corona during the night. Leakage current measurements have also been performed and these verified the improvement achieved by applying coatings.

A comparison is provided in the graphs of Fig. 9. The first illustrates monthly distribution of accumulated charge recorded on the surface of monitored 150 kV porcelain post insulators (i.e. average behavior). It is evident that surface activity takes place, as expected, mainly during the dry summer months, especially from August to October. In the second, the same distribution is shown this time for RTV coated insulators having the same geometry, over the same period of time and installed at the same location. Values of accumulated charge (vertical axis) are therefore indicative of improvements achieved.

It is worth noting that period of activity is different in each case. Although the main pollution problem is experienced during the summer, for RTV coatings surface activity increased mostly during the winter months, especially from November to March. This phenomenon has been correlated to influence of the wetting mechanism, which is different for the two seasons.

During summer, the primary wetting mechanism is condensation while during the winter it is precipitation. Fig. 10 provides a typical example of the influence of these alternative wetting mechanisms on the two different insulator surfaces. In the case of condensation, surface activity is observed only on the porcelain insulator. On the other hand, during periods of rain, activity is seen on both types of insulators. For the first incident, activity on the coated insulator was considerably less than on porcelain. But in the case of the second incident of rain, the same levels of activity were observed. Finally, in the third incident, no activity was present.

Monitoring leakage current, while a valuable tool to fully understand behavior of RTV coatings under such service conditions, is not by itself sufficient to support complete evaluation of coating condition. Performance improvement was verified but these measurements were not able to detect the full impact of any ageing phenomena.

Application of this methodology is typically limited to only a small number of insulators due to costs. Moreover, it is often not possible to monitor the full range of currents with required accuracy. In this case, for example, currents less than 1mA could not be recorded and this was one of the reasons there was no reliable data to compare the coatings offered by different manufactures. Finally, the property of greatest interest in this case is surface hydrophobicity and its corresponding recovery mechanism. Both closely correlate to material properties and can be evaluated only on a macroscopic scale by looking at leakage current alone.

To improve available information on the condition of different coatings installed on Crete, hydrophobicity measurements using the STRI Guide were carried out. These findings demonstrated that, even for the oldest coatings, a hydrophobic surface behavior could still be observed. However, these types of measurements evaluated only the existing surface condition of the coated insulator and offered no information regarding loss and recovery of hydrophobicity (i.e. the stability of this key property). In addition, it is mostly a subjective method and sometimes successive measurements can be at odds with one another.

By most measures, application of RTV coatings on Crete has proven a success, especially given that the payback period of the corresponding investment was less than three years. However, a different era has since been entered, as concerns have come forward regarding how best to evaluate the residual life of coatings and decide on future maintenance needs.

Concerns Regarding Application of RTV Coatings

The first concern for these types of coatings is material selection. Since there are a growing number of different manufacturers worldwide, from the user point of view there is a need for standards with related methods and well-defined criteria to evaluate the quality of any RTV coating under laboratory conditions, ideally before application. Then, after application, the required methodology to monitor condition and performance of these coatings becomes the main issue. While measurements of leakage current and hydrophobicity can be made, experience gained from application of these methods on Crete has suggested that they are not sufficient to provide the complete picture.

It is evident that some material analysis is also required and the question arises as to which parameters must be evaluated and what techniques should be employed. Then, if these methods detect any ageing, the next issue becomes deciding on what remedial actions are required to protect the coatings and extend their service life. Insulator cleaning or high-pressure washing (as in Fig. 8) could probably be employed in some cases. In others, it may be necessary to re-coat. However, it may not be sufficiently clear which should be employed and when to achieve improvement in coating performance with no risk of further deterioration.

Finally, establishment of well-defined end-of-life criteria is necessary in order for users to select the optimum time for replacement or re-coating. In this case, development of standardized methods to remove the previous layer of coating becomes important, considering that any re-coating is probably mostly a temporary remedy. In other words, a complete monitoring and maintenance strategy must be established from the time of coating selection and application. Only this way will it be possible to fully evaluate coating condition and determine when is the correct time for further remedial actions.

Conclusions

Anti-pollution maintenance of insulators at high voltage substations is an issue confronted by virtually every utility worldwide. The main factor that distinguishes the situation for substations from transmission lines is the relatively homogenous service conditions at each station and the corresponding high cost of the equipment to be protected.

In the case of already installed equipment, available remedial measures must be able to improve the pollution performance of existing insulation since the cost of replacement can be considerable. Several methods are available but RTV coatings appear to be the most promising, providing a protective remedy over a long service life.

On Crete, large-scale application of such coatings has allowed improved insulation performance, as verified by leakage current measurements and no need for additional remedies. Nonetheless, there are still concerns to be addressed when it comes to:

1. selecting a coating from among different suppliers;

2. necessary monitoring and maintenance they might need; and

3. optimum replacement time and method.

Powertech Labs Inc.

Canada

Laboratory Center of Koncar Electrical Engineering Institute

Croatia

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The post Substation Pollution Maintenance & Optimizing Use of RTV Silicone Coatings appeared first on .

This edited past contribution to INMR by A.J. Carreira of K-Line Insulators, proposed insulated framing solutions to overcome problems linked to traditional cross-arms. These systems are also claimed to offer benefits from improved safety to increased ground clearances, lower structures and greater operating capacity with reduced right-of-way.

PFISTERER

Germany

Hivolt Power System

China

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The insulated framing solutions that have been introduced as alternatives to traditional cross-arms incorporate robust materials and designs that are both light and modular. Moreover, the silicone insulators used in these applications utilize a proprietary material formulation tested and proven for over many years across different types of service environment. Due to savings in required assembly and set-up labour time, these designs offer major cost reduction opportunities over traditional line designs.

Solutions for transmission applications include designs that allow for overhead ground wires while lightning arresters can be installed on such systems in both distribution and transmission applications. These systems have also been designed to resist bird nesting and wildlife bridging from energized lines to conductive metal or grounded cross-arms. These insulated framing systems even reduce risk of failures linked to vandalism or micro defects in ceramic dielectric materials.

The new designs combine insulators assembled into configurations to perform not only the insulation function of a structure but also the mechanical cross-arm function and have demonstrated their potential to replace most cross-arm configurations. For example, review of insulated framing systems for transmission lines confirms technical advantages when used to replace common H-Frame, Gulfport and similar pole and cross-arm framings using de-energized or live line work methods.

Insulated framing solutions developed for H-frame and Tri-frame systems maintain standard horizontal and vertical conductor spacing and clearances based on voltage and span length of each application. They are also adaptable when replacing cross-arm framing on any three-phase line. In some cases, the design can even be used for multiple circuit arrangements.

Distribution Insulated Framing

Trial installations of the distribution tri-frame insulated framing design were conducted at the training facility of a major Canadian utility in the province of Alberta. During these trials, it took only 6 min for line crews to lift the pre-assembled unit and bolt it into place at the top of the pole. This significantly reduced installation time compared to construction of a traditional cross-arm arrangement that can take anywhere between 40 and 80 min, depending on configuration and crew type. Moreover, the installed cost of this framing solution proved competitive with conventional cross-arm installation.

While the above design is complete with the proprietary K-CLAMP®, other conductor end fittings can also be used with the system. These insulated framing systems can be customized and available for distribution voltages, including 69 kV.

Transmission Insulated Framing

As with distribution designs, insulated framing solutions for transmission lines are intended to offer superior performance compared to traditional treated lumber, steel or composite cross-arm materials. These configurations are designed to perform both the cross-arm and the insulation function on H-frame, Gulfport and other structures supporting nominal voltages up to and including 230 kV.

Flexibility is one of the key characteristics of such designs for transmission applications given that the silicone insulator framing design can be delivered either as modular components or factory-assembled as a single-piece system. Among the maintenance-related advantages of such modularity is that, if needed, any single component is simple to replace in situ, without having to remove the complete system and using appropriate live line tools and techniques. Moreover, in difficult to access areas, line crews can transport the light modular components for on-site assembly with no need for cranes or helicopters.

Simplicity of installation is another aspect of this system which, when acquired as a single-piece assembly, can be easily and safely hoisted to position and quickly bolted to the structure with two machine bolts per pole. Installation time and cost are therefore minimized when placing the framing system into position and attaching it to conductor hardware. Integrated connection points facilitate attachment of standard clamps and conductors directly to the insulated framing system, thereby eliminating need for suspension insulator strings. During one trial installation at a utility in Ontario, for example, the time needed to install this system was only about 22 min – short compared what is normally required to hoist and install a conventional cross-arm arrangement to a structure.

Moreover, installation of cross-arms typically requires assembling suspension strings and then attaching these (or polymeric suspension insulators), the hardware and the conductors. In addition to the labour costs linked to this work, expensive high capacity lifting equipment is often needed to install cross-arms adding further cost when using traditional framing. By contrast, crews from a Canadian utility were able to demonstrate easy, economical and safe installation of a transmission insulated framing system utilizing live line work techniques.

Another important benefit when replacing conventional cross-arms with such transmission line insulated framing is that vertical line clearance to ground or underbuilt facilities is increased (see below).

One way to exploit this added clearance is to allow for greater conductor sag, which permits increasing operating current and thus line capacity. This is achieved when the insulated framing system’s arm is installed at existing conventional cross-arm positions on poles and offers an opportunity to gain vertical clearance equivalent to the length of the suspension insulator string. For example, replacing cross-arms on a 115 kV line makes it possible to gain about a meter of clearance and about 2m can be gained in the case of 230 kV lines. Table 1 demonstrates the potential to increase conductor capacity of an existing 115 kV line by installing fully insulated transmission framing.

The above illustrates the significant increase in line load capacity made possible when replacing conventional cross-arms with transmission insulated framing designs. Alternatively, apart from using the added clearance to increase ampacity, transmission insulated framing systems also offer opportunities to add circuits to existing or new two pole structures. This benefit is especially important these days due to the difficulties related to acquiring new right-of-way routes. With a transmission insulated framing system, the added clearance can be used to install a second (or more) new circuits positioned lower on the structure. Such additional circuits would be considered new assets and significantly increase the value of existing transmission lines.

At the same time, constructing a new transmission line using fully insulated framing systems makes it possible to erect shorter poles than in the case of the conventional two-pole, cross-arm framed design. This is an added opportunity for cost savings. Also, since fixed positioning of conductors on the insulated framing eliminates need for suspension insulator strings, it also eliminates insulator swing under transverse wind conditions.

The benefits of eliminating this displacement component include using existing ROWs more efficiently and reducing land or easement acquisition costs when constructing new lines. It also means that separation distance between phases and structure can be reduced. These reductions in structure width and height allow for design of more compact lines that use fewer materials and require much narrower ROW, both of which contribute to reduced construction costs. Compact lines are also considered more aesthetic. If needed, optional brace insulators can be added to basic insulated transmission line framing.

Such bracing can increase mechanical load capacity of the system by up to 80%, depending on design. Specific increase in load capability depends on the angle between the insulated framing system’s horizontal component and the supporting brace insulator. Increased load then permits longer span lengths, fewer structures and reduced line costs.

Mechanical Testing

Determining the performance capabilities of each insulated framing design required mechanical testing of both distribution and transmission arrangements to determine maximum vertical, longitudinal and transverse load capabilities.

1.Distribution Framing Systems

Appropriate loads were applied at each distribution framing load location, with test arrangements and actual set-up shown below.

Test results show that these framing designs meet MDCL requirements with no noticeable deformation and confirm that these reach and even exceed the SCL mechanical load requirements without failure.

2. Transmission Line Insulated Framing

The testing of most interest in the case of transmission insulated framing was to determine effect of cantilever loads on pole connector plate assemblies and mid connector plate hardware. Arrangements were therefore tested for mechanical suitability under cantilever loads comparable to transmission line post insulators.

Test results for each engineered framing system indicated that designs meet and exceed the mechanical load capabilities of transmission line post designs. For example, the mid connector plate assembly withstood testing with no evidence of deformation, cracking or other damage.

Conclusions

Replacement of deteriorating cross-arms on power lines has become a growing problem for utilities. With this has come the need to develop safer and more efficient framing to maintain dependable uninterrupted power supply. Live line work methods are now the preferred approach when conducting most maintenance activities, including replacing degraded cross-arms.

Insulated framing designs and materials offer new opportunities for electricity providers and contractor personnel to safely and efficiently meet these maintenance and performance requirements. Fully insulated framing requires significantly less labour to erect compared to traditional cross-arms and line crew work exposure (energized or de-energized) is greatly reduced. Insulated framing designs for both distribution and transmission line applications provide advantages, benefits and cost savings over conventional cross-arm framing arrangements and also contribute to system reliability and longer service life of assets. Moreover, these systems can be customized to meet the requirements of a range of different system voltages.

STRI

Sweden

TECNALIA Electrical Labs

Spain

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References

[1] A.J. Carreira, “Insulator Inspection”, 2015 INMR World Congress, Munich, Germany, October 18-21, 2015.
[2] A.C. Baker, R.A. Bernstorf, E.A. Cherney, R Christman, R.S. Gorur, R.J. Hill, Z. Lodi, S. Marra, D.G Powell, A.E. Schwalm, D.H. Shaffner, G.A. Stewart and J. Varner, “High Voltage Insulators Mechanical Load Limits-Part I Overhead Line Load annd Strength Requirements”, IEEE TPWRD-00043-2011, January 2011.
[3] A.C. Baker, “Design and Application of Braced High Voltage Insulator Assemblies”, DEIS IEEE Electrical Insulating Magazine, March/April 2010.

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Leer artículo en español

Many transmission lines across the globe operate at high altitude under conditions of low air pressure and relatively thin air. It is well known that voltage decreases with altitude, whether air gap discharge voltage, conductor corona inception voltage or pollution flashover voltage. The higher the altitude, the more problematic this becomes for external insulation on lines and equipment. In China, for example, where over 60% of the land is at 1000 m or higher, research at specialized test facilities has found that insulator pollution flashover voltage at altitudes of 1000 m and 2000 m are reduced by 5.7% and 11.4% respectively, compared to sea level. Yet another consideration is whether higher sustained UV radiation causes degradation of the polymeric materials used in composite insulator housings.

Years ago, investigators in Peru conducted a laboratory test program to evaluate the condition of 15-year old polymeric insulators removed at random from a 220 kV line running at an average altitude of 4300 m. The research consisted of electrical, mechanical, pollution, hydrophobicity and accelerated ageing tests performed on sample insulators taken down from this line. Among the goals was to evaluate behavior of these insulators after sustained service at such high altitude and estimate useful remaining service life. This edited 2017 contribution to INMR by César Augusto Moreno Cueva of Proyectos de Infraestructura del Peru, reviewed the findings.

DALEKOVOD OSO

Croatia

Klöckner Desma Elastomertechnik GmbH

Germany

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Selection Criteria

A total of 9 test specimens were removed at random from conveniently accessed towers along the 220 kV L-2258 and L-2259 La Oroya-Paragsha Lines, operated by ISA-REP and running through in the central highlands of Peru.

The insulators installed on this line had been supplied early in the 2000s and were selected based on specifications and tests according to IEC 61109.

Laboratory Testing Program

The nine insulator specimens that comprised the test sample were carefully removed, handled, packed, transported to the CITE Energia and Delcrosa Laboratories for unpacking and preparation. The following tests were then performed on each:

1. UV accelerated ageing test;

2. Test of degree of contamination & acidity index;

3. Hydrophobicity test;

4. Test of voltage applied to industrial frequency;

5. Mechanical tensile tests;

6. Dry arc test;

7. Negative polarity impulse voltage test;

8. Inspection & evaluation of condition.

Table 3 shows the procedures set out in the following international technical standards and guidelines in the tests carried out.

1. UV Accelerated Ageing (ASTM G 154)

This test simulated, in accelerated time, the damage that can occur after years of UV exposure and thereby helps verify the life expectancy of an insulator and its resistance to damage after years of service in areas higher than 4000 m. The test was performed in the UV Accelerated Ageing Chamber at CITE ENERGIA and involved the test specimen removed from Tower #160 (middle phase ‘S’) on L-2259. Test duration time was 1000 hours. No physical degradation, cracking or discoloration was found and there was no loss of flexibility observed on surfaces in spite of a slight loss of brightness. Since these polymeric insulators had been exposed to adverse environmental conditions for some 15 years, passing the ageing test and maintaining all their physical and chemical properties confirmed that they are still fit for normal operation.

2. Contamination & Acidity (IEC 60815)

The objective of this test was to verify degree of contamination (ESDD) on each test specimen to serve as a reference for performance of the insulator. The result obtained was verified according to the criteria contained in IEC 60815.

Acidity level in the contamination extracted from the polymeric insulators was higher than neutral (i.e. pH> 7), suggesting that insulators were not at risk of deterioration due to acidity. Degree of accumulated contamination found on the test specimens was equivalent to a Class 2 service environment.

3. Hydrophobicity
This test verified degree of water repellency of the surface of the polymeric insulator test specimens. Higher hydrophobicity offers greater impedance to leakage current and therefore less need for periodic maintenance to avoid pollution flashover. The test method is visual and compares relative surface appearance after exposure to water spray according to a classification provided in the STRI Guide 1-92-1. Tests were carried out individually on 5 test specimens and all showed a minimum of HC3, with 2 having HC1.

Although these polymeric insulators have been exposed to adverse environmental conditions for 15 years and at a height higher than 4000 m, loss of initial hydrophobicity was minimal.

4. Electrical Testing (IEC 60060)

The objective of this test was to verify the basic insulation level at industrial frequency of the polymeric insulators in event of temporary overvoltage during the operation of the line. A standard applied voltage test was performed under dry conditions, with 60 s effective duration starting from the moment the 460 kV test voltage was reached.

Eight test specimens were tested in accordance with the technical data in their catalogue at 460 kV basic insulation level for one minute. The 500 kV nominal voltage resonant system in the laboratory supplied the required test voltage without partial discharge fluctuations at pure wave industrial frequency. No partial discharges were observed on any of the specimens during these individual tests and this verified that they could withstand this standardized voltage at low frequency.

5. Mechanical Tensile Test (IEC 61109)

This test verifies the mechanical resistance limits of sample insulators subjected to a specified tensile stress. It determines how weathering or erosion events could have degraded the FRP core and/or hardware, under criteria of IEC 61109.

Tensile tests performed on 3 polymeric insulator specimens revealed that they were all able to support 75% of their mechanical tensile load (SML). After conducting these tests, visual inspection was performed on insulators and fittings and no signs of damage, abrasion, rupture or deformation were detected.

6. Dry Arc Test (ASTM D495)

This test is designed to determine an insulator material’s resistance to arcing due to leakage current, arc currents or atmospheric discharges. The standard used is ASTM D495, which specifies that, along a sample of the polymer material, two separate electrodes are connected at a distance of 6.5 mm. A voltage of 1000 V is then applied, initiating an arc that generates heat of the type that can produce superficial damage. Test residues can be black (carbonaceous) if the polymeric material is composed of organic bases such as EPDM, polyethylene, natural rubber or white if the base material is composed of a silicone base material. The result of the test confirmed that the polymeric material used in the test insulator specimens is silicone (silicone).

7. Negative Polarity Impulse (IEC 60 060-1 / 2)

The aim of this test is to verify that arcing distances in air resist a transient specified impulse type surge that could cause short-term disturbances. The non-disruptive impulse voltage test is performed with a voltage having a waveform of 1.2/50 μs, as specified in IEC 60060-1 / 2 and intended to simulate a lightning-type surge. This impulse test was performed at the Delcrosa Laboratory up to the limit of its impulse generator (1300 kV) for which, according to the standard, the test was performed on a partial insulator length of 2400 mm. The test requires a minimum of 3 pulses of negative polarity.

After the three tests of lightning impulse applied to each polymeric insulator, a 1300 kV negative impulse holding voltage was presented without contouring arc to satisfy compliance with standard environmental conditions. The value of compliance of the basic insulation level was extrapolated linearly to the total length of the polymeric insulators installed at altitudes greater than 4000 m. It was thus concluded that the impulse hold voltage for the respective insulator length was 1680 kV.

ICMET Craiova – National Institute For Research, Development And Testing In Electrical Engineering

Romania

ABB and PEHLA Laboratories

Germany

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Summary of Test Results & Conclusions

Results obtained in various tests performed on a total of 9 randomly selected insulator specimens were all satisfactory and within acceptable parameters according to relevant international standards and technical guides. These polymeric insulators had been in continuous service for 15 years at an altitude of about 4000 m and subjected to adverse climatic conditions from sustained UV to ice to rainfall to high winds. Laboratory tests demonstrated conclusively that the condition of these sample insulators was good in terms of their dielectric and mechanical characteristics as well as the texture and hydrophobicity of the polymeric materials, which remained similar to that of a new insulator.

Insulators installed on the 220 kV La Oroya-Carhuamayo-Paragsha-Vizcarra lines belonging to Peru’s ISA Business Group have been determined to comply with strict quality standards for polymeric insulators used on transmission lines. The ISA Group’s specifications for polymeric insulators require high temperature vulcanized (HTV) silicone material that provides sustained hydrophobicity to prevent pollution flashovers and that reduces leakage distance compared what would be needed for ceramic equivalents. In addition, this polymeric material has been found to be resistant to tracking to assure long life and stability, even under adverse environmental conditions.

The core rods are made of brittle fracture resistant ECR glass and the interface between core and rubber housing has an optimum seal to prevent moisture penetration and partial discharges. The results of laboratory tests validate the quality of these silicone insulators.

Finally, based on results of these tests, it was concluded that the service life of polymeric insulators installed on ISA Peru lines has so far not been adversely affected. This in spite of being in-service for 15 years under adverse weather conditions and at altitudes higher than 4000 m. Nevertheless, it is recommended that similar tests be conducted at intervals of from 5 to 10 years to further validate behavior of these polymeric insulators under such conditions. The polymeric insulators that are presently in operation on transmission lines of ISA Peru are deemed to have high probability to continue continuous service, with an expectation of a total useful service life of over 25 years.

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PFISTERER

Germany

EB Rebosio SRL, A Gruppo Bonomi Company

Italy

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Generic MV & HV Cables & Accessories: Developments at IEC & IEEE

Over the past decades, the volume of power cables being produced has been increasing by 8 to 10% each year. While most of these new cables are for distribution networks, annual growth in application of HV cables has recently been in the double digits. Key issues driving this trend are growth in the renewables sector and demand from within urban areas where, due to land limitations, cables are being installed in preference to overhead lines. Apart from volume, lengths of cable systems are also increasing and HV networks that cover hundreds of kilometers are no longer rare. Such longer lengths create challenges not only for the factory but also when it comes to on-site testing. Lengths of distribution networks are increasing as well, often covering 15 to 20 km.

In regard to applied insulation material, there is now a clear trend to use of only polymer insulated cables. Polymeric materials such as polypropylene (PP) have been developed and are being used for HVDC cables. New materials present new challenges, especially in terms of diagnostic assessment, such as dielectric losses.

Modern day production processes for power cables and their accessories are well-controlled and one of the main product philosophies is being ‘fit for purpose’. For example, insulation thickness is kept to the minimum necessary to reduce costs. But this approach comes with the downside that almost every workmanship error will eventually lead to a system defect.

Within the standards and guidelines there has not been a lot of change over the past decade and these continued to be based mainly on withstand testing only. Although diagnostics are recommended, no threshold values are mentioned. Within CIGRE, several working group activities have been undertaken both for MV and HV cables. A new brochure, TB841, has been published that discusses alternative methodologies for after-laying testing of HV and EHV cables. Although the brochure was not the original goal, it nevertheless provides a valuable overview of which methods can be applied. For MV networks, an active Working Group on MV cable asset management (B1.58) closed in 2022. This WG aimed to propose asset strategies to be applied on several type of cables (i.e. polymer, paper, mixed) for commissioning, after-repair and maintenance testing. All test and diagnostic methods, i.e. the complete toolbox, were to be described along with a pros and cons analysis of each, apart from a section dedicated to asset management.

MV Off-Line Site Testing, Diagnostics & Monitoring

Underground MV power cables have become an important component of modern distribution networks. Experience from network operators has shown that localized degradation, cable joints and terminations often constitute the ‘weak spots’ in these systems, apart from factors such as ageing, water ingress, inadequate workmanship and utilization of inappropriate or defective accessories. Hence the need to deploy testing and diagnostic techniques on both new and serviced-aged MV cable systems to ensure highest possible reliability, as outlined in guidelines and standards such as the IEEE 400 series and IEC 60502-2.

The standards today are written mainly for cable withstand testing. While there is some guidance on diagnostic methods for TanDelta and partial discharges (PD), this is either limited or outdated. Looking to the IEEE 400.2 TanDelta tables, for example, one can question: ‘will the cables from 2015 still have the same recommended trending limits as cables installed in the 1980s and 90s? Also, looking to PD diagnostics on paper-insulated cables, can any threshold values be defined since this type of cable is not designed to be PD-free?

Withstand tests typically require application of continuous voltage at a prescribed voltage level (normally above nominal operating voltage) for a prescribed time. The cable system under test will either ‘Pass’ or ‘Fail’. If the cable system fails, i.e. breaks down during testing, it will either be repaired or replaced. A withstand test can be classified either as a simple withstand test or a monitored withstand test. The latter differs from a standard withstand test in that other parameters are also monitored e.g. dielectric losses, leakage current or partial discharges. Fig. 1 shows a generic schematic of a monitored withstand test (MWT).

As a basic principle, a simple or monitored withstand test is designed to consistently overstress a cable system to some acceptable risk level. As such, for a withstand test to be effective, it must include the following fundamental elements: defined voltage exposure, repeatable voltage exposure and a well-defined failure rate.

The most commonly used excitation voltages are VLF (very low frequency), either sinusoidal or cosine-rectangular, followed by DAC (damped AC). In some cases, power frequency or near power frequency is used and, in rare cases, a soak test is also performed. Use of DC voltage on extruded cable systems for withstand testing has been discouraged by IEEE 400.1, ICEA S-94-649-2004 and IEC 60502-2.

Withstand testing for medium voltage cable systems is performed mainly in the context of commissioning/acceptance/electrical testing after installation of new cable systems. The goal of a withstand test during commissioning is to ensure the cable system is safe to energize and for quality control purposes. The impact of cable failure during testing is considerably lower and repairs can be made relatively quickly and cost effectively compared to in-service failures and resulting unplanned (emergency) outages and repairs. Additionally, a withstand test can also be performed on aged cable systems.

It should be noted that in the case of aged cable systems monitored withstand testing is recommended above simple withstand testing. Moreover, some industry guidance/standards recommend reduced test voltages relative to cable commissioning contexts. The decision to conduct withstand testing should always weigh the cost of failure during testing versus the cost of in-service failure and subsequent unplanned outages and repairs. The main disadvantage for withstand testing of aged cable systems is that there is a risk of inducing failure during the test, especially for cables that are already degraded. This could cause additional complications in aged cable systems due to issues such as lack of spare components, difficult accessibility for repairs, outage availability, etc. Additionally, in cable systems that are already degraded, residual life could be reduced by applying withstand testing with a voltage higher than nominal voltage.

Generally, it can be stated that simple withstand testing will give a certain degree of confidence when putting a cable into operation. However, not all defects can be detected during a simple withstand, no matter what excitation voltage is used. Applying diagnostic methods as in a monitored withstand or diagnostic context helps ensure higher reliability of the cable system.

Looking to diagnostic methods on MV cables, these can differ in core and context specific methods. Core methods are VLF tan delta, TDR (time domain reflectometer), PD testing and jacket testing. These methods are suitable for almost every cable type. Despite lack of consensus on acceptance criteria for most of these, such methods are well known and documented. Modern devices are easy to operate and the core methods should be considered as the basic toolbox for cable testing and diagnostics, providing the user with a fast and reliable result.

The purposes of context specific methods are multiple and these can be recommended during a commissioning test for baselining purposes, or at higher level of diagnostics or troubleshooting to increase accuracy of the measurement. Typically, these context specific measurements are applied on critical system infrastructure such as in nuclear power plants. These methods should be considered an ‘added value’ to the core methods. Due to their specificity, some may require more experienced operators in order to obtain exploitable results. Context specific methods include FDR (frequency domain reflectometry), neutral resistance measurements, FDS and TDDS (frequency domain spectroscopy and time domain dielectric spectroscopy), insulation resistance measurements, PDC (polarization, depolarization current measurement) and conductor resistance measurements.

Two main core methods being widely applied are VLF TanDelta and PD testing. VLF TanDelta measurements were originally intended to detect water trees in degraded polymer insulated cables. However, as cables being installed have become more resistant to water tree growth, especially long bridging water trees, the purpose of VLF TanDelta measurement has been changing as well. Experience gathered over the past decades is moving from a global measurement to a local measurement. Comparing phases with one another makes it possible to identify local issues, however these are not localized. Still, this gives operators important information about the reliability of their networks and is extending application of VLF TanDelta measurements to mixed cables systems.

PD testing on MV cables is broadly performed (mainly off-line). A proper test strategy should be applied to:

• Maximize the probability of identifying PD inducing defects (reducing risk of false negative results);

• Discriminate such defects internally and from noise (reducing risk of false negative and false positive results);

• Localize identified defects (allowing for targeted repairs);

• Allow for condition assessment that can allow for pass/fail assessment or potentially deferred investment, ideally through relating results to in-service (operating) conditions.

A wide range of offerings exist among PD equipment vendors and service providers, ranging from ‘black-box’ type approaches with proprietary algorithms only used by service providers, to fully customizable and adaptable systems requiring high levels of expertise, to ‘push-button’ type boxes which in principle can carry out measurements for unskilled users.

To obtain a better understanding of how to deal with all such options and of their impact on accuracy and performance of field PD assessment, a good starting point is to understand the basic technical considerations that most influence the outcomes of a PD measurement.

The most commonly used systems for MV networks are single-ended PD measurement systems and use of either DAC, VLF CR or VLF sinusoidal excitation voltage. There is lack on guidance when looking to trending limits, especially for aged cable systems. Apart from user experience and recommendations, there is no standard. In addition, as for the differences between test voltage sources, there will likely never be general guidance on acceptance levels.

The numbers of monitored MV cable systems currently is still low. Demand is rising but, apart from the issue of cost, there are also some technological hurdles, as reviewed in Table 1. With on-line PD methods, the chance of false positives or false negatives is still high, which is not acceptable to most end-users.

Finally, with all measurements that can be performed for both withstand testing, diagnostic testing or monitoring, proper data handling is also of importance. The need for an asset management system/software is constantly increasing, not only in terms of handling measurement data but also in regard to such data as age, location, number of faults, etc. In the past, diagnostic measurement was limited and could be treated differently. Now, with the current broad use of diagnostics methods by utilities, only by applying proper asset management, guided by software, will it become possible to increase the availability and reliability of power cable networks.

HV Cables: On-Site Testing & Diagnostics

Since reliable energy transmission and distribution are fundamental for every economy, the various aspects of maintaining quality control for newly installed as well as in service power cables is of great importance. Key questions for power utilities in regard to maintaining/updating internal procedures for reliable cable network operation include:

1. How best to perform, in a sensitive yet non-destructive manner, detection of poor workmanship defects in newly installed HV cable circuits?

2.How best to perform non-destructive diagnostics of HV cable circuits in service to determine their actual condition?

Over the past 30 years of testing distribution and transmission power cables, different test methods have been introduced and are currently in use, including: continuous AC resonant (ACR), damped AC (DAC) and very low frequency (VLF). From the start of offshore wind farm installations, such onshore methods have also been applied for testing offshore power cables. Unfortunately, considering the greater need for quality control for offshore HV cables and for long onshore HV cables, all these methods can present challenges, as illustrated in Table 2. Different studies during the last 20 years have shown that regarding voltage stresses, partial discharge occurrence and dissipation factor measurement, differences can exist between the ACR and DAC methods. Nonetheless, when used by experts, both are a valuable tool for assessment. It has been documented in recent publications that when testing transmission power cables, DAC after-laying and diagnostic testing allows sensitive PD detection. Moreover, using DAC calibrated PD detection is possible on-site, with background noise below a few tens of pC.

IEC standards such as 60840, 62067 and 63026 place emphasis on manufacturing and therefore most of their content deals with testing aspects in the factory. An up-to-date description of methods for on-site testing of high voltage cables has long been necessary but is taking place only slowly, especially on alternative on-site test methods for ACR. Moreover, most standards provide no up-to-date guidelines regarding field experience in after-laying and maintenance testing of cable circuits. CIGRE’s TB 841 is not standard but rather a recommendation and provides recent methods and experience. Traditionally recommended over-voltage testing with a binary test outcome, i.e. ‘breakdown’ or ‘no breakdown’, will reveal major defects. But PD detection should be added when possible and a check should always be made for the risk of igniting faults that would not have occurred under operating voltages.

Some TSOs are in the process of developing or have already developed their own more dedicated procedures to test newly installed cables. These procedures are based on service experience and selected IEC documents as well as on existing international standards made in cooperation between power companies, cable manufacturers and testing organizations. These guidelines have come to represent the current state-of-the-art for non-destructive methods for both after-installation and maintenance testing and diagnostics.

Introduction of on-site PD monitored voltage withstand testing of power cables has opened the possibility of reproducible conditions for PD detection. Based on research and about 20 years of testing of power cables up to 230 kV at numerous different 3^rd parties offering after-laying testing, the following parameters could be recommended as general criteria for DAC and ACRT testing to determine if a cable has passed the test and is sound for operation (see Table 3).

Submarine Factory & On-Line Cable Testing

Submarine cable systems differ in several respects from underground cable systems. Among the more notable differences are manufacturing and delivery lengths being much longer as well as use of factory-made joints. Manufacturing lengths typically depend on the maximum time an extrusion line can run before it must be cleaned. This converts to maximum length through the relationship between volume that can be extruded per unit of time. Volume of insulation that can be extruded per unit of time relates mainly to voltage class and cable cross-section, i.e. it generally takes more time to extrude a kilometer of cable of high voltage class or large cross-section. That means that typical manufacturing lengths of the highest voltage classes can be 10-20 km, whereas much longer lengths can be extruded in one run when the voltage class is lower and/or cross-section is smaller. Mass-impregnated cables are produced batch wise, where length depends on size of the impregnation vessel. The focus below is on extruded cable technology.

Delivery lengths that are finally loaded onto the installation vessel are much larger than individual manufacturing lengths. For that reason, manufactured lengths are jointed together using so-called factory joints to form one large delivery length. Maximum delivery length is determined largely by factory storage capacity, i.e. size of turntables, and also by maximum load the vessel can handle and safely transport. Maximum delivery lengths are defined by the size and maximum weight capacity of the vessel’s turntables. The outer diameter and height of such turntables define the volume while the vessel’s properties define the maximum weight of the stack. Diameters of the turntables in most modern vessels can reach 20-25 m or more and the maximum weight the different vessels can carry sometimes surpass 10,000 tons. As such, maximum delivery lengths of power cables, while greatly dependent on cable and vessel type through their size and weight, nowadays easily reach well over 100 kms. Looking to the future, lengths of 150 km or more seem realistic. These different considerations about length can have profound implications on testing.

While cables are available in many different types, it is possible to categorize them according to certain hierarchies. Firstly, AC cables can be divided into 1- and 3-core types. The 3-core cables share the same armor package and the 3 cores can be installed in a single lay. By contrast, single core AC cables need 3 separate laying campaigns per phase. DC cables need only two poles (plus and minus) and, although often laid in a bundled fashion, the two poles are still two independent separately armored cables.

AC cables have a limitation in useful length between two connecting stations since they generate capacitive current. Depending on voltage class, such lengths are roughly maximized to between 50 and 150 km. By contrast, DC cables do not face this limitation and can attain route lengths of several hundred kilometers. This means that testing DC cables can face practical challenges due to the possibility of their significantly increased lengths.

AC cables (including submarine type) have been implemented at 500 kV whereas DC cables are commonly installed and projected at a level of 525 kV. Route lengths can be several hundreds of kilometers and it seems probable that the 1000 km barrier will eventually be surpassed using DC technology. It is clear that probability of a small defect in a cable system increases with its length. As such, testing, as one component of quality control, becomes very important. Nevertheless, it is also important to note that no testing can replace good workmanship and proper quality control of all steps – from sub-supply, to design, to installation. In this context, testing is rather an integral part of QA and QC.

Moreover, testing can also be categorized into three hierarchal classes: qualification testing, manufacturing and installation testing, and on-line testing & monitoring. Passing a pe-qualification test (PQ) or the addition of an extension of it (EQ) means that the manufacturer of a certain technology can supply such cable systems on a commercial basis, covered by such standards or recommendations. Holding a successful type test (TT) certificate means that the supplier can provide a certain technical solution on a commercial basis that meets the performance characteristics for an intended application, as covered by the standards or recommendations. These tests are conducted on a limited length of cable (tens to above 100 m) and only a small number of accessories. Such tests can be viewed as a student having passed a university exam but with no guarantee that they will do a good job every single day of the week in their upcoming career.

Manufacturing and installation tests cover every single meter of cable and every accessory. Such tests are routine tests, FAT (factory acceptance test) and possibly also a harbour test. The extent of these tests depends on cable system type as well as on the contract. Sample tests are performed on a sample of the projected cable length and number and serve to ‘measure’ the quality of design at certain points in time along the project line. The harbour test is intended to hand over responsibility for the project from manufacturer to installer in cases where these are different entities.

The challenge in testing long submarine cables comes with the long manufacturing lengths and very long delivery lengths. Typical extruded AC cables are routine tested at 2.0-2.5 U₀, the lower multiple representing the higher U₀ voltage class. The historical reason for this was that one did not want to exceed certain electric field thresholds above which the cable would age in a different way than from service. In regard to long cable lengths, there is another reason that practically limits the test factor. The higher the test factor (and with that the voltage), the larger the capacitive loading current. The test equipment must be able to deliver that. Originally, this problem was self-limiting because cables with the highest voltage classes often had the shortest delivery length due to the inherent issue of capacitive loading in service. This challenge has now returned with the introduction of extruded DC cables.

The recommendations state that the manufacturing lengths are to be tested with an AC voltage such that the AC stress is 20 or 23 kV/mm at the conductor screen. The challenge increases given the realization that the recommendation asks for an AC and PD screening test of the factory joints, if applicable. The term, “if applicable” was added because the challenge now becomes clear. Several manufacturing lengths are being factory-jointed together and, if possible, each joint shall be locally PD-measured. This means that the joint and the cable lengths before and after the joint shall be put on voltage, even though for short duration. The last joint, adding the last manufacturing lengths to the previous sections, make up the full delivery length.

HVDC cables having delivery lengths of 100 to 150 kms or more and tested at 23 kV/mm places severe challenges on the AC resonant test equipment, which must become very large. For example, the capacitive loading current during testing of a large cross-section 525 kV cable, tested in the interval 400-440 kVac, becomes around 1 kA if fed at one end and half that value if fed from both ends. These values are significant and care must be taken to ensure that the cable sheath can carry the current. Similarly, the heat generated in the cable stack also has to be considered.

One way of overcoming this challenge is to allow for other testing methods. TB 852, for example, offers a different way of addressing the QC of the joint using X-ray inspection. Another emerging technology is acoustic detection and in-line ultrasonic sensing of extruded core is a sometimes-utilized technology. Moreover, based on that technology where the cable is moving through a static head with ultrasonic sensors, another technology has now been developed as well, i.e. keeping the object fixed and static, while the ultrasonic sensing head is moving instead. Such technology could prove particularly useful in controlling quality of the factory joint insulation and its interfaces. Ideally, one could then limit size of the AC resonance test set by optimizing it only for testing manufactured cable lengths. Alternatively, accept the maximum length that the AC test resonance set can handle, utilizing AC and PD testing up to that length, and rely on acoustic sensing for the joints after that length.

Installation tests can be divided into two categories as well. One category summarizing the tests during installation and the second the classic after-installation test. The after-installation test for AC cable systems is again limited to the maximum route length specific to the voltage class. PD tests are then typically performed locally on the accessories. Obviously, there is a need for a mobile resonance or DAC set if the test is not performed by connecting to the grid.

Lately the question has arisen whether one should perform an AC after installation test on installed underground extruded DC cable systems (possibly including local PD tests on the prefabricated accessories). Considering the inherently long lengths of DC cable systems, the AC test set-ups become very large, as explained above in relation to factory testing. There is as yet no experience relating the effectiveness and therefore the benefit of such AC testing on performance of extruded DC cable systems. The complexity of this test must therefore be weighed against its perceived effectiveness. Clearly, without much experience on what is being gained, the choice becomes less technical and more economic or of a risk management nature.

Obviously, if one could measure partial discharges under DC voltage online, one would have the perfect monitoring tool. But the challenges here are significant. Electrical noise levels of the outdoor system are often high and the repetition rate of the discharges are inherently much lower under DC than under AC voltage. Nonetheless, research has been pushing progress in addressing that problem and, although not yet solved, this remains a distinct possibility in the future. CIGRE Working Group D1.63: Partial discharge detection under DC voltage stress will result in a Technical Brochure that summarizes the state-of-the art of the industrial practice of this phenomenon.

Cable systems these days are often equipped with an integrated fibre (FIMT) for temperature and acoustic sensing purposes. Although limited in sensing length, progress is being made to increase this. Acoustic sensing is mainly used to detect external damage or imminent such, whereas temperature sensing could preventively sense changes in the external thermal environment.

Finally, in regard to offshore windfarm cables, all the above remarks are valid for both interconnector cables and offshore wind export cables. They are also valid in some respects for array cables, but these are inherently shorter and have different design aspects.

Summary & Conclusions

The biggest challenge in cable system test methodologies is finding the right balance between efficacy and not damaging against a background of acceptable budget and realistically sized testing equipment.

When it comes to reliability of cables in general, there is much confidence in testing at the production location as being well-understood, controlled, effective and standardized. That is why users are looking for similar quality control for accessories and systems after installation.

Lengths of several hundreds of kilometers in HV networks are no longer rare.

Most commonly used systems for MV networks are single-ended PD measurement systems that make use of either damped AC or very low frequency excitation voltage. There is still lack on guidance when looking to trending limits of especially aged cable systems. Apart from user experience and recommendations, there is no standard and, as for the differences between the test voltage sources, there will most probably never be general consensus/guidance on acceptance levels. With all the measurements that can be performed for both withstand testing, diagnostic testing or monitoring, proper handling of data is also of utmost importance. There is a growing need for an asset-management system/software that not only handles the measurement data but also includes key statistics such as age, vintage, location, number of faults, etc.

Studies by different parties over the past 20 years have shown that there are some differences between ACR and DAC methods in regard to voltage stresses, partial discharge occurrence and dissipation factor measurement. Still, both methods, when used by experts, are a valuable assessment tool. Traditionally recommended over-voltage testing with a binary test outcome, i.e. ‘breakdown’ or ‘no breakdown’, may reveal major defects. But PD detection should be added where possible and a check should always be made of the risk to ignite faults that would not have occurred under operating voltages.

As concerns submarine factory and online cable testing, maximum delivery lengths of cable depend greatly on the cable and vessel type through their size and weight but can now easily reach well over 100 kms. This will likely rise to 150 km or more in the future. The recommendations state that the extruded DC cable manufacturing lengths are to be tested with an AC voltage such that the AC stress is 20 or 23 kV/mm at the conductor screen. The challenge increases when realizing that the recommendation asks for an AC and PD screening test of factory joints, if applicable. Testing of the last joint, adding the last manufacturing lengths to the previous ones making up the full delivery length, places severe demands on the AC resonant test equipment, which needs to be very large. Other means, such as acoustic screening methods, might be a tool for future development.

All insulation defects resulting from installation that might reduce the system quality under AC will produce PD and that is one way to identify them.

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References

[1] E. Gulski, R. Jongen, J. Parciak, J. Sieminski, “Modern Methods for Quality- and Condition Assessment of High Voltage Cables” 2020, VDE VERLAG GMBH, Berlin, Offenbach, ISBN 978-3-8007-5353-6.
[2] Smit J, van Riet M, Staarink B, “Non-destructive after laying test with PD localization”, Jicable 2019, paper D3-4
[3] IEC 60840: Power cables with extruded insulation and the accessories for rated voltages above 30kV up to 150kV Test methods and requirements;
[4] IEC 62067: Power cables with extruded insulation and the accessories for rated voltages above 150kV,
[5] IEC 63026: Submarine power cables with extruded insulation and their accessories for rated voltages from 6 kV (Um = 7,2 kV) up to 60 kV (Um = 72,5 kV) – Test methods and requirements, 2019;
[6] IEEE 400-2012: Guide for Field Testing and Evaluation of the Insulation of Shielded Power Cable Systems Rated 5 kV and Above;
[7] IEEE 400.4-2015: Guide for Field-Testing of Shielded Power Cable Systems Rated 5 kV and Above with Damped Alternating Current Voltage (DAC)
[8] HD 632 S2 (CENELEC): Power cables with extruded insulation and their accessories for rated voltages above 36kV (Um=42kV) up to 150kV (Um= 170kV);
[9] UK Power Networks, ECP 11-0006, Engineering Commissioning Procedure, ECP 11-0006, HV insulation testing 2018;
[10] IEEE 400.3-2006: Guide for PD Testing of Shielded Power Cable Systems in a Field Environment;
[11] IEC 60270: Partial discharges measurements;
[12] IEC 60885-3: Test methods for partial discharges measurements on lengths of extruded power cable;
[13] IEC 60060-3: High Voltage test techniques Part 3: Definitions and requirements for on-site testing;
[14] Cigre TB 420: Generic Guidelines for Life Time Condition Assessment of HV Assets and Related Knowledge Rules, 2010;
[15] E. Gulski, R. Jongen, B. Quak, J. Parciak, A. Rakowska, Fifteen Years Damped AC Testing and Diagnosis of Transmission power cables, Jicable 2019, paper D3-1.
[16] Leufkens P, Gulski E, Jongen R, Damped AC for Commissioning & Diagnostic Testing of HV Cable Circuits, Proceedings of INMR World Congress (INMR 2019), 20-23 October 2019, Tucson, Arizona, USA, ISBN: 9781713803256;
[17] P. Cichecki, Testing and Diagnosis of High Voltage and Extra High Voltage Power Cables with Damped AC Voltages ISBN: 978-83-952726-0-8;
[18] F.J. Wester, Condition assessment of power cables using partial discharge diagnosis at damped AC voltages, ISBN 90-8559-019-1;
[19] CIGRE: Technical Brochure 841 After laying tests on AC and DC cable systems with new technologies, 2021
[20] PTPiREE, Frame instructions for exploitation of power cables up to 110 kV, 2011;
[21] PSE, Power cable lines 220 kV and 400 kV, 2020;
[22] M. Jeroense, Quality Control of HVDC Cables – The next industry challenge, JICABLE 2019, D8-3;
[23] TB 852, Recommendations for testing DC extruded cable systems for power transmission at a rated voltage up to and including 800 kV, CIGRE, 2021;
[24] S. Sutton, P. Willmott, “Determining Cables Metrics Using 3D Ultrasonic Scanning”, CIRED 2017, Paper 0418;
[25] IEEE 400.2-2013: IEEE Guide for Field Testing of Shielded Power Cable Systems Using Very Low Frequency (VLF) (less than 1 Hz).
[26] IEC 60502-2-2014:Power cables with extruded insulation and their accessories for rated voltages from 1 kV (Um = 1,2 kV) up to 30 kV (Um = 36 kV) – Part 2: Cables for rated voltages from 6 kV (Um = 7,2 kV) up to 30 kV (Um = 36 kV)
[27] Neetrac CDFI, Phase 2, Cable handbook 2016 – Chapter 9 Withstand testing
[28] ICEA S-94-649-2004: Concentric Neutral Cables Rated 5 Through 46 kV
[29] R.Probst, F.Petzold, H.Putter: Excitation Voltages for Partial Discharge Diagnostics on Medium Voltage Distribution Cables, IEEE T&D Denver 2018
[30] H.Putter, F.Petzold, P.Legler: Offline PD diagnostics using several excitation voltages, CIRED 2017 Glasgow, Paper 0049
[31] H.Putter, F.Petzold, D.Götz: Innovative Solutions for On-site Diagnosis of Distribution Power Cables, IEEE T&D Orlando 2021, Paper 0041
[32] A.Lathouwers, P. Jansen, E. de Meulemeester: TenneT’s giant leap to be able to replace 140 substations within next 10 year, while in service and coming from different lay-outs, CIGRE Paris 2020, B3-104

The post Overview of Cable Testing: Standards & Technologies appeared first on .

This edited contribution to INMR by Michele de Nigris summarizes recent work by Ricerca Sistema Energetico (RSE) in Italy to assess and improve the resilience of overhead transmission lines against extreme weather events. Special attention focuses on strong winds, heavy rain and snowfall and wildfire.

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Continuous improvement in resilience of overhead lines in Italy has been an effort involving several parties, including the country’s national energy regulator (ARERA), which issued directives to incentivize network operators to enhance resilience of their power system by ensuring both rewards and penalties. Network operators were mandated to assess performance of their assets under extreme weather events and propose actions to improve resilience. RSE served as the technical arm to develop, propose, validate, and monitor methods to assess the effectiveness of the measures proposed to be taken before, during and after extreme events, i.e., anticipation, preparation, absorption, adaptation, rapid recovery, and sustainment of critical system operation.

The method, developed jointly with Italian TSO Terna, has since been approved by the regulator and is now part of the transmission grid code. It is based on an advanced probabilistic approach, and deepens the connections between threats such as extreme weather events, component vulnerabilities (i.e., their susceptibility to these threats), and power system contingencies (i.e. failures) potentially leading to extended service degradation and blackouts.

Below is a summary of this, with focus on threats linked to extreme events and their consequences for overhead lines as the input to set up measures to increase resilience.

Extreme Weather Events

The European Copernicus program identified 2024 as the hottest year on record. Notably, global temperatures exceeded the 1.5°C increase above pre-industrial levels for the first time. November 2024 ranks as the second warmest month in history, with an average surface air temperature of 14.1°C, which is 0.7°C higher than the 1991-2020 average. Even of greater concern are sea temperatures due to their critical function as regulators of global climate. Data from 2024 show a concerning rise in damage due to prolonged drought (+54.5% compared to 2023), river floods (+24%), and pluvial floods (+12%). Italy, for example, is divided between regions experiencing chronic water shortages and those inundated by excessive rain, highlighting systemic inadequacies in adapting to extreme weather. Among the most adversely affected regions, Northern Italy experienced 198 extreme weather events, followed by Southern Italy with 92, and Central Italy with 61.

Electrical power infrastructure is particularly at risk because it is extensive, exposed, and interdependent. Overhead transmission lines cross forests, mountains, and coastlines, making them frontline victims of environmental extremes. Moreover, the situation in 2024 is not new. In recent years, several outstanding events caused extensive damage to power infrastructure and data from the Italian TSO confirm this dramatic trend. Fig. 1 depicts recent electrical system disruptions linked with extreme weather.

Among the events affecting the transmission system in Italy were:

• Storms & Winds:
Devastating windstorms such as the Vaia storm of October 2018 (with up to 200 km/h gusts) toppled 42 million trees and damaged power lines on a massive scale. Severe winds and winter storms often threaten the stability of transmission towers and lines.

• Floods & Landslides
Back-to-back heavy rainfall events in 2014 & 2015 triggered floods and debris flows, destabilizing transmission tower foundations and causing extended outages. Overall, between 2013 and 2020, landslides and floods accounted for about 9% of energy supply disruptions from extreme events in Italy. In terms of permanent impact to infrastructure, 58% of the damage recorded during landslides and flood events affected line poles and 17% the conductors.

• Wildfire
2017 and 2021 saw unprecedented wildfire activity in Italy, with the former dubbed an “annus horribilis” for number of fires and 2021 breaking the record for burned area (~150,000 ha). Hotter, drier weather has lengthened the fire season and increased extreme fire behaviour.

• Compound Hazards
These hazards often compound. For example, drought and heat favour ignition and spread of wildfire, or storms cause both flooding and landslides – challenging grid reliability. A severe snowstorm in early 2017 in central Italy caused line failures and concurrently hampered wildfire response by forcing transmission line shutdowns for firefighter safety.

Evaluating Threats: Methodology

To investigate the evolution of environmental hazards across extensive diverse regions, researchers have developed global gridded datasets, known as re-analyses. These consist of physically based reconstructions of historical conditions, generated through numerical weather prediction models that assimilate archival observations.

Such datasets provide three-dimensional representations of atmospheric and terrestrial variables at sub-daily intervals over historical timespans of varying length. The most used global reanalysis, developed by the European Centre for Medium-range Weather Forecasts (ECMWF) is the ERA5 dataset. It covers the globe with a spatial resolution of around 30 km and an hourly temporal resolution, with 137 vertical levels from the surface to a height of 80 km.

To reproduce and understand past and present threats over Italy, an atmospheric reanalyses dataset, called MERIDA was developed. MERIDA consists of a dynamic downscaling of the ECMWF global reanalysis ERA5, using a Weather Research and Forecasting (WRF) model, configured to describe typical weather conditions. The computational domain is defined using two grids with a spatial resolution of 21 km and 7 km respectively, with the internal grid centred over Italy, as shown in Fig. 2.

The dataset has hourly temporal resolution and spans over 30 years, with 22 different meteorological variables computed at 40 different altitude levels, comprising 1.5*1012 records. These datasets allow researchers to study past extreme events, understand their characteristics, and track their evolution over time. They are also essential to developing warning systems by identifying environmental conditions that favour occurrence of such events.

Moreover, to assist Transmission System Operators to develop robust resilience strategies, it is essential to utilize climate projections derived from advanced climate models. These models simulate the Earth’s future climate over coming decades, integrating scenarios based on varying concentrations of greenhouse gases that influence the planet’s radiative equilibrium, as well as factors such as demographic trends, land use, and economic development trajectories.

To assess the potential impact of extreme meteorological events on overhead transmission infrastructure, future climate scenarios are analysed using an ensemble of model simulations under 2 distinct configurations: Representative Concentration Pathway (RCP) 8.5, RCP4.5 and RCP2.6. RCP8.5 represents a high-emission scenario with minimal mitigation, whereas RCP4.5 reflects a pathway incorporating moderate greenhouse gas emissions reductions and RCP2.6 considers outstanding greenhouse gas emissions reductions.

For the Italian context, long-term climate projections are conducted using an ensemble of high-resolution (~12 km) regional models from the Euro-CORDEX initiative, each rigorously selected and validated for reliability. Both projections based on previously mentioned RCP 4.5 and 8.5 are considered. This methodology enables comprehensive evaluation of risks associated with climate-driven hazards that can affect the structural and operational integrity of transmission networks.

Strong Winds

Strong winds constitute an increasingly significant meteorological threat for operators of electrical networks. In recent years, Italy witnessed severe windstorms, with the Vaia event of late Oct. 2018 standing out in intensity. The storm affected northeast Italy, unleashing wind gusts between 100 and 200 km/h and resulting in widespread and protracted disruptions to electricity supply. Damage to transmission infrastructure was attributed both to direct mechanical stress exerted by extreme wind and to secondary effects such as the toppling of trees onto overhead lines.

Accurate analysis of extreme weather events within the context of Italy’s complex geomorphology requires spatial resolutions surpassing the 7 km offered by the MERIDA dataset. To this end, a high-resolution analytical tool has been developed: the Atlante EOLico ItaliANo (AEOLIAN) – a state-of-the-art Italian Wind Atlas designed primarily for energy system planning applications. AEOLIAN provides a 30-year (1990–2019) archive of wind data at an exceptional 1 km spatial resolution and hourly temporal granularity, covering Italy both on and offshore, across various measurement heights.

To illustrate the benefit of employing such high-resolution datasets in reconstructing wind fields over complex terrain, Fig. 3 presents a comparative analysis of 10m wind speeds recorded at the Monte Cesen meteorological station (Veneto Region, approx. 1500m above sea level) during the Vaia event, evaluated against previous reanalysis products, namely MERIDA and MERIDA HRES—the latter offering an improved 4 km horizontal resolution.

AEOLIAN demonstrated superior accuracy to observed wind series, whereas the coarser-resolution datasets exhibited more pronounced deviations at several timesteps. This highlighted the limitations of their modelling configurations and spatial resolutions in accurately reconstructing wind fields over complex terrain. Moreover, it is essential to underscore the distinctive nature of events such as Vaia, whose destructive potential depends greatly on slope orientation and local topography. Indeed, within a span of merely a few hundred metres, areas subjected to severe damage co-exist alongside zones that remained unaffected.

Fig. 4 illustrates the situation at another complex-terrain substation, Monte Verena. In this instance, all datasets displayed comparable behaviour, with AEOLIAN not exhibiting a clear advantage in capturing measured wind trends.

Collectively, this study underscored the intrinsic difficulty when trying to reconstruct localized extreme events, even when employing high-resolution datasets.

From a climate standpoint, application of modeled datasets—incorporating mean and maximum daily wind intensities—has enabled development of predictive scenarios spanning the periods 2021–2050, 2041–2070, and 2071–2100. These scenarios characterize both average and extreme aspects of wind intensity, as illustrated in Fig. 5. Notably, wide variability among the ensemble models (with standard deviation fields frequently exceeding the magnitude of projected change) complicates extraction of definitive trends, particularly concerning occurrence of extreme wind events—an outcome corroborated by prior studies.

Operationally, when forecasts indicate likelihood of a major windstorm, grid operators proactively implement preventive actions, such as real-time reconfiguration of load flows, to mitigate consequences of potential line outages. The aftermath of the Vaia storm, for example, prompted Italy’s TSO to expedite programs focused on reinforcing transmission towers in wind-exposed regions and expanding vegetation management along corridors to reduce risk of tree falls affecting lines.

In addition, advances in real-time monitoring—utilizing weather stations and LiDAR systems deployed along critical network spans—have enhanced operational responsiveness to wind-induced damage. Over the long term, undergrounding transmission lines, where technically and economically feasible, offers complete mitigation against wind-related hazards, although associated costs remain prohibitive for most high voltage routes.

As a result, primary adaptation strategies continue to prioritize fortification of overhead lines with deployment of stronger towers and reduced span lengths in high-risk zones. At the same time, refined outage management protocols such as rapid deployment of repair crews and use of mobile transformers can bolster network resilience in the face of increasingly severe wind events.

Extreme Precipitation

The overarching impact of total precipitation—comprising both snowfall and rainfall—on overhead transmission infrastructure is intrinsically linked to excess water infiltration into terrain. This generates surface runoff capable of inducing urban flooding in densely paved regions and greater inundations when river discharges exceed the capacity of channel banks. Moreover, water infiltration leads to soil saturation, diminishing its cohesive properties and thus predisposing terrain to landslides.

Within this analytical framework, the MERIDA and MERIDA HRES reanalysis tools have proven indispensable for depicting both synoptic meteorological phenomena—primarily originating from frontal systems. These are distinguished by prolonged and persistent precipitation over extensive areas with the potential to induce landslides and major flooding (e.g. the 1994 Piedmont flood). Also, convective events that give rise to highly intense, localized storms can trigger catastrophic flash floods and debris flow episodes.

Figs. 6 and 7 illustrate the efficacy of historical datasets in replicating the cumulative precipitation associated with such extreme events: the 1994 Piedmont flood, which resulted in 70 fatalities and economic losses amounting to approximately 1.2% of Italy’s GDP for that year and the 2011 urban flooding in Rome, where 120 mm of rain fell within 2 hours, causing substantial disruption to urban infrastructure and electrical substations. In both scenarios, the MERIDA reanalysis products demonstrated their ability to reconstruct these extreme events, with modeled precipitation patterns and quantities aligning closely with observations from the Italian rain gauge network.

Specifically, Fig. 6 depicts accumulated precipitation for the Piedmont flood in Nov. 1994, juxtaposing MERIDA output with interpolated station data from the Italian observation network. MERIDA successfully captured both the principal precipitation peak and its magnitude, corroborated by ground observations. Similarly, Fig. 7 displays the accumulated precipitation map for the Rome urban flooding event of Oct. 2011, contrasting MERIDA reanalysis with observed accumulated precipitation at Baccano and Roma EUR sites, as reported by local rain gauges.

The MERIDA dataset accurately replicated the intense and localized precipitation events at Baccano and Rome (Panel a), albeit with a local underestimation in correspondence of Baccano (Panel b). A more accurate estimate was obtained for ROMA EUR station (Panel c).

Availability of more than 3 decades of data from the MERIDA reanalysis has enabled application of the Generalized Extreme Value (GEV) method to estimate statistical return periods and, consequently, determine the probability of occurrence of extreme precipitation events, encompassing both persistent synoptic systems and short-lived, high-intensity convective storms. The results presented in Fig. 8 delineate regions of the Italian peninsula that are most susceptible to extreme precipitation, differentiated by rainfall duration.

Panel a, which illustrates the probabilities of occurrence of events exceeding 50 mm in 3-h, identifies regions with the greatest propensity for intense, localized convective storms. These are concentrated mainly in Liguria, and in the Ionian sectors of southern Italy, where formation of low-pressure systems over the western Mediterranean facilitates uptake of moisture from the sea. Upon encountering complex coastal topography, these air masses release heavy, spatially confined downpours.

Panel b depicts likelihood of events surpassing 100 mm of precipitation within a 24-h period. Here, spatial distribution of high probabilities closely tracks regions where the most significant rainfall is attributable to winter frontal systems interacting with mountain topography of the Alps and Apennines. This dynamic results in prolonged, abundant precipitation across northern Italy, Liguria, and the southern areas of Calabria and Sicily.

To systematically assess projected patterns of extreme precipitation across Italy through a climatological lens, the WMO ETCCDI climate extreme index R99PTOT was employed. This index is tailored to characterize climatic extremes by quantifying frequency of exceptionally wet days—defined as when daily precipitation exceeds the 99th percentile of the established reference period. Temporal analysis reveals a pronounced trajectory toward intensification of such extremes throughout this century, with regional manifestations most evident in the north and coastal sectors of Italy.

The magnitude and spatial distribution of these anomalies vary according to the different Representative Concentration Pathway scenarios (RCP2.6, RCP4.5, and RCP8.5), as illustrated in Fig. 9.

Geo-Hydrological Hazards

Geo-hydrological hazards, including flooding and landslides, constitute significant risks to electrical infrastructure. Extreme flood events can compromise operational capacity of hydropower plants which are pivotal for balancing critical hydrological regimes and safeguarding downstream regions. Landslides can impact power lines, leading to local failures that have the potential to cascade across the network.

To assess and quantify these risks, a novel process-based numerical framework—CRHyME (Climatic Rainfall Hydrogeological Model Experiment)—has been developed. CRHyME is a spatially distributed, basin-scale model designed to simulate the initiation and propagation of rainfall-induced geo-hydrological hazards, specifically shallow landslides and debris flows, and to quantify their respective magnitudes. The model’s architecture integrates the physical mechanisms by which hydrological dynamics influence and potentially trigger geo-hydrological instabilities at the catchment scale, encompassing a suite of slope stability processes.

Geo-hydrological threats from intense precipitation are principally categorized as shallow landslides and debris flows. These phenomena can originate either on hillslopes or within drainage networks, emerging from collapse of the superficial soil layer. Notably, debris flows are characterized by higher water content, enabling them to travel with greater velocity and over more extensive distances compared to shallow landslides, with substantial volumetric growth driven by erosive entrainment. The CRHyME Model incorporates predictive formulations for the triggering of both processes.

The CRHyME Model is currently undergoing development. Below, two representative applications are presented: the first involves a retrospective analysis of historical geo-hydrological events, while the second explores projections of future geo-hydrological hazards affecting high voltage lines traversing two catchments in the Emilia region of Italy. For retrospective analyses, outputs from the MERIDA reanalysis served as input data, whereas future projections were generated using three distinct climate models from the EURO-CORDEX programme.

The Emilia region experienced severe geo-hydrological phenomena in Oct. 2014 and Sept. 2015, during which multiple shallow landslides were triggered, that subsequently evolved into debris flows and flash floods. The most significantly impacted watersheds were the Parma basin during the Oct. 2014 event, and the Trebbia and Nure basins during the Sept. 2015 event (see Fig. 10). This region is of strategic importance for the Italian transmission network since several high voltage lines intersect the affected catchments.

According to the literature, pylons represent the most vulnerable components within electrical power systems since they are highly susceptible to collapse if impacted by rapidly moving landslides. While the network is sometimes capable of compensating for isolated tower failures, redundancy is not always guaranteed, thereby demanding enhanced attention in infrastructure planning. Exposure of high voltage lines to geo-hydrological threats—specifically shallow landslides and debris flow failures—has been evaluated in relation to their spatial distribution within the catchments (see Fig. 10).

For the Emilia region case study, simulations using the CRHyME framework encompassed a 5-year period, spanning from Sept. 1, 2011 to Sept. 1, 2016, during which major geo-hydrological events (Oct. 13, 2014 and Sept. 14, 2015) were recorded in the area. MERIDA reanalysis data—including daily rainfall and temperature—served as the basis for these simulations, ensuring a robust representation of the climatic conditions influencing occurrence of shallow landslides and debris flows within the study domain.

Evaluation of CRHyME’s capability to identify debris flow initiation during the October 2014 and September 2015 events (see Fig. 11) was conducted through Receiver Operating Characteristic (ROC) analysis. In most cases, the model demonstrated superior performance compared to a random classifier, exhibiting sensitivity values between 0.1 and 0.2, and generally higher specificity contingent upon chosen slope stability parameters. Across these simulations, detection of debris flow failures was particularly effective within a confined valley catchment, corroborating in situ field observations.

Specifically, the Nure watershed achieved the highest classification scores, followed by the Parma basin with intermediate performance, whereas model representation of slope instabilities was comparatively limited for the Trebbia catchment.

Given the potential for recurrence of such phenomena, the CRHyME model was executed under the most severe climate change scenario (RCP8.5). The climate projections are derived from the EURO-CORDEX project [21], [46], with the RCP 8.5 scenario employed (see Table 1). For the analysed EURO-CORDEX models (including mod2, mod3), the CRHyME framework was applied to future simulations spanning the period from Jan. 1, 2006 to 1 Jan. 1, 2075.

Extended simulations were undertaken to assess the likelihood of landslide occurrence at specific locations. Strictly speaking, landslide events are not inherently periodic, as subsequent geomorphological alterations can fundamentally change local slope stability dynamics. However, in the absence of explicit modelling of such features, frequency is utilised as an indicator to identify the most conditionally unstable regions warranting particular attention. Figs. 12 and 13 present the frequencies of shallow landslide and debris flow failures under projected climate change scenarios, as derived from the mod2 simulation. Comparable spatial distributions were observed in simulations mod3. Within both catchments, the most unstable regions are depicted in red, whereas areas exhibiting relative stability are shown in white. Overlays of high-voltage powerline networks on these hazard maps facilitate a spatial analysis of risk exposure, enabling the identification of sectors most susceptible to shallow landslides and debris flows.

Findings indicate that the Trebbia basin’s highest risk sector for power line vulnerability is situated near Salsominore, while in the Parma basin the area of greatest concern is proximal to Berceto. Notably, the pylon with the maximal predicted probability of debris flow failure is geographically close to zones that underwent severe geo-hydrological disturbances in Sept. 2015 and Oct. 2014, thereby corroborating the pronounced landslide susceptibility of these localities.

Prospective geo-hydrological hazards are likely to continue posing significant risks in these sectors. Accordingly, implementation of mitigation strategies (see Fig. 14) or potential relocation of pylons, is advised to prevent overhead line failure and mitigate risk of future blackouts.

Wildfire

Concern regarding wildfire hazards has intensified in recent years, particularly across the Mediterranean. Prolonged heat waves, extended drought, and strong winds—conditions exacerbated by climate change—now occur with greater frequency, creating an environment conducive to wildfire propagation.

Ignition and sustenance of fires involve 3 principal factors: combustible material, oxygen, and elevated temperatures. Italy’s terrain, notably in southern areas, is abundant in combustible vegetation, including scrub, dry grasses, and wood, contributing to fuel availability. While ambient temperatures in Italy seldom reach thresholds for spontaneous combustion, critical summer conditions can facilitate ignition and markedly accelerate fire spread, with wind serving as primary vector for propagation.

The European Forest Fire Information System (EFFIS) systematically monitors burned areas throughout Europe, compiling comprehensive data on incidence and extent of wildland fires across European member states with annual updates. EFFIS records indicate a pronounced escalation in wildfire occurrences throughout Italy over the past decade, peaking in 2017—a year designated as annus horribilis—and culminating in a record of 150,000 hectares affected in 2021. Projections suggest that frequency and severity of wildfires will continue to rise in coming decades, driven by increasing prevalence of fire-favourable weather conditions.

Wildfires inflict significant damage on critical infrastructure, particularly transmission lines, which are frequently de-activated to facilitate firefighting efforts and mitigate safety risks. Between 2017 and 2023, approximately one thousand transmission line deactivations were documented as direct or indirect consequences of proximal wildfires. Such disruptions exert considerable influence on continuity of electricity supply as well as market stability for end-users.

Formulation of an effective forecasting methodology for wildfire-prone conditions is paramount for preparedness and timely intervention. Direct prediction of wildfire ignition, however, is not feasible, since naturally occurring fires are rare in the Italian context, whereby lightning strikes with absence of precipitation. Most ignition sources are human caused. Nonetheless, it is still possible to predict the environmental and meteorological conditions that predispose an area to fire initiation and propagation.

Forecasting fire spread risk is therefore critical to enable Transmission System Operators to proactively plan for and manage potentially hazardous situations at specific locations. Development of a robust early warning system requires characterization of each site with respect to land cover, vegetation type, slope, elevation, and soil moisture. By integrating detailed weather data, it then becomes feasible to compute a fire danger index.

A meteorological indicator known as the Fire Weather Index (FWI) has been developed and adopted globally. FWI quantifies the propensity for wildfire ignition and expansion under prevailing meteorological conditions and now forms the backbone of most operational wildfire monitoring frameworks worldwide. FWI also serves as a quantitative measure of fire danger, derived from meteorological inputs. It is calculated daily using midday temperature and relative humidity at a height of 2 m, wind speed at 10 m, and total precipitation over the preceding 24-h. These variables modify FWI values from the previous day in an iterative process, necessitating an initial condition and a designated spin-up period to ensure accurate computation.

Structurally, FWI comprises 6 distinct components: 3 that pertain to the moisture content of various fuel types, 2 that describe rate of fire spread and fuel consumption, and one that quantifies fire intensity as the energy output per unit length of the fire front. Fig. 15 presents a schematic overview of these components. Analysing the scheme reported, it becomes possible to note that weather information is an input for all components of the final danger index. Therefore, accurate estimation of local weather is essential to obtain a reliable fire danger value.

Higher FWI values correspond to higher fire hazard. Classes of hazard have been defined by EFFIS, according to values reported in Table 2.

In the current study, FWI has been employed to assess average fire danger across Italy, with the aim of identifying regions exhibiting increased risk due to geomorphological and climatic factors. Calculation of FWI was based on historical analysis of meteorological parameters—including precipitation, temperature, wind speed, and relative humidity. The data utilized derived from an internal reanalysis dataset, MERIDA HRES-OI, which provides a spatial resolution of 4×4 km with hourly temporal granularity, amalgamating numerical weather simulations and observational data. Fig. 16 reports assessment of FWI for the timespan 2005 to 2020. Moreover, FWI underpins a prototype warning system designed specifically for the Italian Transmission System, delivering forecasts of fire danger for each 4×4 km grid cell up to 3 days in advance.

Long-term average FWI provides insight into the climatology of a region and enables identification of areas most susceptible to wildfire, thereby supporting strategic infrastructure planning. Nevertheless, use of average values alone does not account for variability year-to-year, which can result from transient synoptic-scale phenomena and significantly influence fire risk in any given year.

For example, 2017 was marked by numerous wildfire events across Italy. Fig. 17 presents average FWI distribution for summer 2017, facilitating direct comparison with the climatological baseline shown in Fig. 16. Notably, the data reveal elevated FWI values in the Islands, northern Calabria, and throughout Apulia, regions that typically exhibit lower baseline fire danger classes, with FWI values generally ranging from approximately 15 to 30. This contrast underscores the exceptional nature of wildfire risk in these areas in 2017.

To rigorously evaluate FWI as a reliable indicator of wildfire danger and to facilitate its application in an effective warning system, a comprehensive analysis has been performed correlating historical fire events with corresponding FWI values. Specifically, wildfire occurrence catalogued in the EFFIS Burned Area Dataset for the Italian Peninsula between 2010 and 2020 was compared against FWI values derived from the MERIDA HRES-OI dataset on the day of ignition, classified according to categories outlined in Table 2.

Results, depicted in Fig. 18, demonstrate that 87% of ignitions occurred during periods characterised by “high”, “very high”, or “extreme” fire danger, with most small and medium-sized fires associated with “high” FWI days. The largest wildfire events (exceeding 400 hectares of burned area) occurred mainly under the most severe FWI conditions, with a clear escalation in event magnitude corresponding to increasing FWI danger class. Conversely, fewer small wildfires were observed in the upper FWI categories, underscoring the propensity for fires to escalate rapidly and exceed containment under adverse meteorological conditions. These findings support the conclusion that elevated FWI values are strongly associated with potential for wildfires to spread uncontrollably.

Having established the efficacy of FWI as an indicator of wildfire danger, a prototype fire danger warning system has been developed. To illustrate this methodology, reference is made to July 19, 2022 and the major wildfire that occurred in Massarosa, Tuscany—an event that posed significant risk to power infrastructure supplying a densely populated coastal region, including Viareggio, during the peak tourist season.

Fig. 19 displays FWI values calculated from meteorological forecasts issued the previous day (July 18), with wildfire locations recorded in the EFFIS Burned Area Dataset for 2022-07-19 denoted by purple markers. It is evident that multiple areas exhibited extreme FWI values, attributable to prolonged high temperatures and a persistent deficit of precipitation, leading up to the ignition event.

Notably, daily FWI values on high-risk days can greatly exceed the summer average (see Fig. 16 for comparison), often surpassing 75. Moreover, all wildfire incidents occurred in zones characterized by extremely elevated FWI levels, which further substantiates use of this index for early warning and fire danger assessment. The Massarosa wildfire ultimately affected some 860 hectares and caused significant disruptions to the regional electrical grid. The area impacted is clearly delineated in SENTINEL-2 satellite imagery.

Fig. 20 represents FWI values over the area of interest as well as shape of the area burned. It should be noted that the forecast issued 3 days in advance (lead time = 72 hours) greatly underestimated fire danger of the area; the following 2 forecasts, issued 48 and 24 hours before fire ignition corrected this and yielded an FWI value of 60+, more than 40 points higher than the July average for that area (seen in Fig. 21).

This change in the forecast is due to the 3-day forecast giving a lower value for wind speed than the other two, the latter being more realistic given that newspapers reported the presence of a strong Mistral wind.

Overall, looking at many other case studies, FWI values stay consistent throughout the forecasts, despite their being issued at different times (with the earliest being issued 3 days before the fires). This suggests that FWI could probably be used as a reliable fire danger index, even in forecasts with lead times longer than 3 days.

Another interesting observation of note from Fig. 19 is that there is a large inhomogeneity in the index along the peninsula and in the islands. This reflects the ability of the index to be sensitive to local variations in weather conditions, and also the capability of the WRF model to accurately describe the complex geography of Italy. It should also be noted that while there were high FWI values in Sicily and in Sardinia, no wildfires broke out. This illstrates that FWI does not indicate probability of fire ignition caused by human activity but rather ease of fire spread in the event of ignition.

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Conclusions

Overhead power lines are exposed to intense weather events that can impact their performance and threaten their structural integrity. Transmission system operators are required to implement adequate measures to increase resilience of power networks.

Short term operational decisions and long-term planning and network reinforcement measures can be carried out using an advanced probabilistic approach to risk. The methods set up in the case of Italy required computing the severity, extent and duration of the threats, in terms of associated probability distributions, knowing evolution of meteorological phenomena over geographically spread infrastructure. To assess evolution of threats during the recent past and during the current period, an atmospheric reanalyses dataset, called MERIDA, has been developed and validated for strong winds, extreme precipitation, landslides and wildfires.

Long term climate-related projections are carried out using an ensemble of high-resolution regional models, adequately selected, and validated, to elaborate future climate scenarios under different greenhouse gas emission pathways (namely, RCP8.5, RCP4.5) and RCP2.6. Extreme precipitation is expected to increase locally, mainly over northern regions and over coastal areas, whereas no significant change in occurrences of extreme winds were detected in the analyses.

Geo-hydrological hazards are frequent and related to meteorology and climate but their magnitude is difficult to quantify. Nonetheless, the former is necessary to carry out proper risk assessment and define strategies for increasing resilience of electrical infrastructure. This is particularly true under the projected future climate change scenario whereby intensification of extreme events is expected with high confidence.

The new CRHyME represents a novelty in the panorama of classical spatially distributed hydrological models. It tries to couple together slope failure models with the hydrological component and includes extreme event reanalysis and climate change scenarios in the simulation. Resilience plans based on application of the method described are adopted with approval of the national regulatory Authority.

A fire danger assessment for Italy has been performed by calculating FWI over the entire country over the past two decades. Results comparing wildfires in Italy with FWI values show a clear relationship between the two, and FWI is therefore valid as a fire danger indicator.

A fire danger forecasting tool to support transmission system operators in their real time operation of the power system has been set up and implemented. This tool could prevent critical situations and avoid prolonged outages and economic losses by assuring better preparedness and more rapid response to fire events. Preliminary results look promising. Further analyses and improvements are underway, for example refining description of the soil, which is a fundamental element in determining FWI.

Acknowledgements
This work has been financed by the Research Fund for the Italian Electrical System under the Three-Year Research Plan 2025-2027 (MASE, Decree n.388 of November 6th, 2024), in compliance with the Decree of April 12th, 2024. None of the content of this article has been AI-generated; the author did, however, use MSCopilot for editing and styling purposes. This is, as mentioned, a review paper. It refers to numerous recent works carried out in Italy by researchers and experts from RSE, namely: A. Abbate, F. Apadula, R. Bonanno, E. Ciapessoni, D. Cirio, E. Collino, F. D’Amico, P. Faggian, M. Lacavalla, L. Mancusi, A. Pitto, S. Sperati, A. Trevisiol, F. Viterbo, L. Vadacca. A close collaboration has been established with TERNA and the following experts have been involved: L. Minto, F. Pietrocola, S. Talomo, C. Vergine.
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