Conventional approaches to reduce grid congestion typically involve expanding, enhancing, or reconstructing electrical infrastructure. Although such long-term investments may ultimately be necessary, the technology behind Dynamic Line Rating (DLR) offers more immediate and cost-effective alternatives to relieve congestion.

The post Dynamic Line Rating & Enhancing Resilience of Transmission Networks (Video) appeared first on .

This edited past contribution to INMR by Dr. William Chisholm, in co-operation with Kinectrics, proposed a process to review and quantify the performance of OHGW systems to rank possible renovation options. In some cases, these should consider replacing OHGW protection with other components, including optical fiber ground wire (OPGW) installed below the phases. With suitable arresters, this underbuilt OPGW can be energized at modest voltage to support future monitoring of infrastructure.

EB Rebosio SRL, A Gruppo Bonomi Company

Italy

PFISTERER

Germany

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Lightning Performance Measures & Goals

Lightning Tripout Rates, Outages per 100 km per Year
Overhead transmission line design guides weave aspects of lightning protection through¬out their pages. Each also devotes a specific chapter to the prevention of shielding failures (where lightning terminates directly on an energized, insulated phase) and mitigation of backflashovers (where lightning terminates on an earthed component, but the resulting voltage rise exceeds the lightning impulse insulation strength). These guides rely in turn on specialized IEEE Standards and CIGRE references for the series of calculations made to establish the “shielding failure rate” (SFR) and “backflashover rate” (BFR) that are added to establish the total lightning outage rate, expressed in units of outages per 100 km of line length per year. While the ground flash density (Ng, in flashes per km2 per yr) varies considerably, by a factor of 100:1 in North America, utilities tend to adapt their new overhead line designs to deliver about the same outage rate. One historical security classification includes:

• Class “C”, < 4 lightning outages per 100 km per year
• Class “B”, < 1 lightning outage per 100 km per year
• Class “A”, < 0.5 lightning outages per 100 km per year

Class “A” security is the recommended design target for ultra-high voltage (UHV) lines [9] at system voltage  1000 kV AC.

Cost per Avoided Customer Momentary Dip, USD $/CMD
A simple cost/benefit analysis was carried out to capture the main costs of overhead groundwire protection for 100-km line sections, ranging from 230 kV single circuit to 765 kV double circuit steel lattice construction Applying inflation of 54% from 2003 to 2023, the costs of overhead groundwire lightning protection include:

1. 1. 1. Increased capital cost of line:
         a. Twin OHGW, 3/8” 7/1 EHS Galvanized Steel Guy Wire, USD $700k for 2×100 km
         b. Taller and stronger structures, 600-1000 kg each, 250 m spans, $3.7 M per 100 km
      2. Capital cost of generation to meet peak loss, valued at USD $2/W:
         a. For low-reactance phasing of double circuit lines (ABC/CBA), < 1 MW/100 km
         b. For single circuit lines, 1 to 7 MW/100 km
         c. For superbundle (ABC/ABC) phasing of double circuit lines, 0.2 to 26 MW/100 km
      3. Present Value cost of I²R losses from currents induced in OHGW, valued at USD $0.23/kWh:
         a. Continuous loss about 9x less than peak loss as running current typically 1/3 of peak
         b. 3% interest rate over 50 years, $15 M per 100 km for a 345 kV double circuit line

The “benefits” of OHGW protection were estimated using the number of customers affected by a momentary lightning outage, which is derived from the power transfer capability. The utility investment to avoid a customer momentary dip (CMD) in an area of modest Ng = 1 flash/(km2-yr), varies from about USD $0.015 to $0.21. Double circuit superbundle configurations incur higher losses, with a resulting cost about of $0.12/CMD. Low-reactance phasing of double circuit lines is preferred from this aspect because OHGW investment is only $0.02 per avoided dip.
The amount that a utility now spends to avoid customer momentary dips defines the value of additional investments in lightning protection. In many cases the business case for additional improvement is weak because the OHGW protection has proved to be highly efficient.

Lightning Performance, HV Lines of 1940s & 1950s

The median span length with wood H-frame structures in Fig. 1 was 183 m, compared to 252 m for the steel lattice structures. In 1955, the electric utility industry relied on meteorological station measurements of “Thunder Days” to normalize performance against local lightning activity. With the data provided, it is possible to estimate a “critical current” I_crit for backflashover (kA) from the provided values of lightning impulse strength (kV), average footing resistance (Ω) and a factor accounting for parallel overhead groundwires on shielded lines. Fig. 2 shows a rough downward trend in normalized outage rate as I_crit increases.

When the critical current I_crit > 200 kA, it is often considered to be “lightning proof”. Fig. 2 shows good performance – less than 0.1 outages per 100 miles per yr per thunder day – for all but one line with I_crit > 200 kA. In a typical region with TD = 40 days/yr, equivalent to N_g = 4 flashes/km²/yr, a performance of 4 outages / 100 mi / yr (2.5 outages / 100 km / yr) meets “Class C” security.

Lightning Performance of Modern HV Lines
The North American Electric Reliability Corporation (NERC) still mentions lightning as a “hard-to-predict” challenge in its 2023 State of Reliability Overview. Lightning outages rank sixth behind Weather, Failed AC Circuit Equipment, Unknown, Vegetation and Failed AC Substation Equipment when considering the power (MVA) capacity affected by automatic transmission outages. Lightning outages would be expected in the summer season (June to October) in Fig. 3 but thunderstorms on March 22, May 21 and December 30, 2022 were the events classified as extreme.

Fig. 3 suggests that the consequences of lightning outages were well managed in 2022, through a suite of countermeasures that includes direct stroke protection, efficient fault detection and reclosing, and highly meshed networks that are resilient to the loss of any individual element. This is also reflected in the 2022 NERC Transmission Availability System Data. Considering systems rated above 200 kV, lightning contributed 649 momentary outages (23%), second only to “unknown” at 940 (33%). By contrast, sustained outages from lightning contributed only 0.38% to the total duration of sustained outages.

Shielding & Backflashover Performance of EHV/UHV Lines

As illustrated with the lightning performance data from 1955, backflashover analysis computes “critical current” I_crit , the impressed current at each tower that causes the voltage on one of the line insulators to slightly exceed its lightning impulse strength. When the return stroke exceeds I_crit , there is a line-to-ground fault that is sustained by the power system until the fault is detected and cleared.

The backflashover rate of EHV and UHV lines is expected to be rather low because each structure has a large value of I_crit. The typical structures in Fig. 4 are large, with a typical effective perimeter P > 50 m of foundations in the soil. For each tower, the local soil resistivity ρ (Ωm) is divided by P to obtain the earthing resistance R_f = ρ/P. The preliminary estimate of I_crit is given by dividing the insulator critical flashover voltage (CFO, kV) by Rf measured at the base of the stricken tower. The backflashover outage rate is given by the probability that Icrit is exceeded, multiplied by the number of flashes to the line per 100 km per yr.

Recent experience suggests that high phase-conductor voltage bias and large separations among conductors in the EHV and UHV systems of Fig. 4 result in a high fraction of shielding failures.

The field performance of the 500 kV shielding system in Fig. 4 was good, with 99% of the lightning flashes causing no outage, 0.4% finding their way to a phase conductor and causing a shielding failure flashover, and 0.6% causing a back-flashover. This performance was established in a region with N_g = 5 flashes/ km²/yr, leading to 131 flashes to the line per 100 km-yr and an outage rate of 1.28 per 100 km per yr. While good, this outage rate does not meet the Class “B” security criterion listed above.

The backflashover performance of the UHV design in Fig. 4 was observed to be 8 times lower than that found for the 500 kV design, because the dry arc distance is higher (5.9 m versus 3.3 m) for the UHV design. Since the UHV design is taller (140 m versus 100 m), it attracted 33% more lightning (1859 versus 1394 flashes). Since the separation among conductors of the UHV design is larger than the 500 kV design, its shielding failure rate was slightly higher. Overall, the UHV design delivered 0.71 outages per 100 km per yr, missing the Class “A” security criterion.

Rebuilding / Refurbishing Project Objectives

Improve Overall Reliability
The wind and ice loading recorded in the Canadian province of Newfoundland are exceptional. Meteorological loading conditions in the 1960s and 1970s considered ice thicknesses of between 0.5 to 1.5 inches (12.7 to 38.1 mm) of radial ice for the ice load sag curve, used to establish safe clearances to ground. Operating experience revealed larger ice load conditions for 230 kV transmission lines on the Avalon Peninsula. The rebuilding of steel tower 230 kV transmission lines on the Avalon Peninsula between 1999 and 2002 utilized a larger radial ice thickness, which, in turn, became the ruling ground clearance sag curve for these transmission lines. Calculations utilizing the sag – tension programs revealed that the equivalent “hot” conductor 18 sag curve for the rebuilt transmission lines limited the maximum conductor temperature to 80°C.

This utility has undertaken a series of rebuilding projects to improve reliability, with the following specifics:

• 1984: Ice storm failures in 22 km zone with 51 mm icing design. Upgraded to high strength 563 kcmil ACSR phase conductor; retain unshielded configuration.
• 1993-1996: Replace porcelain insulators with cement growth problems.
• 2001: Add lightning arresters to every insulator on one (of two parallel) 230-kV line.
• 2002: Following 1994 ice storm, rebuild 230 kV line for 76.2 mm ice load.
• 2003: Increase thermal rating of 230-kV line.

INMR has documented the response of Ontario and Quebec utilities to the devastating ice storm of 1998. This series of three sequential icing events, with no melting periods between, led to overall accretion as high as 80 mm, compared to design levels of 2” (50.8 mm) of glaze ice with density 0.9 g/cm³. The first 735 kV lines in the Manic – Québec corridor were commissioned between 1965 and 1973. Fig. 5 shows how a 735 kV line built after 1973, at left, survived the ice storm while a similar adjacent line built earlier exhibited a cascade failure of many towers.

The vertical capacity of the newer towers on the left in Fig. 5 was probably less than for the older collapsed towers, based on design optimization. However, improved balancing of loads among components, combined with the use of anti-cascading structures, succeeded in keeping the newer line intact during the ice accretion and shedding processes.

After loss of OHGW from ice storms, at least two different utilities have considered leaving them off, and providing the unshielded phase conductors with transmission line surge arresters (TLSA) instead. This approach was implemented by Transelectrica, the Romanian transmission system operator as described in INMR.

Improve Lightning Performance
In a CEATI “Best Practice” design Guide, a matrix of ground flash density N_g crossed with soil resistivity ρ (Ωm) was used to classify the best practices for lightning protection. As an example, a region with low lightning activity (N_g < 0.5 flashes per km² per yr) and high resistivity (ρ ≥ 1000 Ωm) could consider the use of unshielded transmission lines. This alternative is especially attractive in rough terrain as well as in areas where ice accretion may exceed 25 mm.

This alternative does not work in all regions. For example, Georgia Power constructed a 110-kV wood-pole H frame line of 100 km from Sumpter to Tift County, Georgia in 1936. The phase conductor height at the tower was 15.7 m. This region reported a thunder day level of 58 days per yr. Thunder is a poor predictor of N_g, but this converts to N_g = 6.3 flashes /(km²-yr). Modern records from lightning location systems (LLS) show a cloud-to-ground Ng ≅ 4 /(km²-yr), and a “total” lightning density of 40 events/km²/yr.

The insulation strength of the seven-ceramic-disc / 2.13 m wood crossarm system was reported as 1335 kV + CFO measured with a 1.5/40 wave. Unshielded, the surge impedance of the 336 kcmil ACSR conductor (diameter 18.3 mm) is 244 Ω in two directions. The critical current I_crit is (1335 kV / 244 Ω) = 5.5 kA. This will be slightly higher considering the extra strength for negative polarity, but about 99% of the lightning flashes will have higher peak current. Nearly every lightning stroke will cause an outage.

This line had an outage rate of 14.5 per 100 km – yr in the period 1936 to 1946. The performance of the unshielded line was bad enough that it was rebuilt in 1946, using twin overhead groundwires and continuous counterpoise. After installation of the OHGW and counterpoise grounding system, the outage rate fell to 0.12 per 100 km per yr, meeting Class “A” security requirements.

There are several other examples of projects that were undertaken specifically to improve the lightning outage rate of a transmission line, generally undertaken after a decade of unsatisfactory service. The rebuilding projects all made use of OHGW. As mentioned earlier, poor lightning performance of a pair of 230 kV transmission lines with separate structures on a common right-of-way led to a significant number of simultaneous outages, and loss of supply to the Avalon Peninsula in Newfoundland, Canada. This was mitigated by fitting non-gapped line arresters (NGLA) across every insulator string on one of the two lines.

Increase Power Flow
Recent assessments highlight the need for increased power transfer in many electrical grids. Higher power transfer can be achieved with a combination of aggressive operation (using retrofitted instrumentation supporting dynamic line rating (DLR), increased aluminum area A_a, increased steel area A_s (to support the aluminum at high operating temperature), substitution of composite materials with low thermal expansion coefficients for steel, or increased system voltage. Modest improvements can also be achieved with conductor geometries that are perfectly compensated, such as 500 kV four-conductor bundle or 345 kV BOLD designs, that consider surge impedance loading (SIL) in the design. These considerations form an important part of CIGRE Technical Brochure 792. Larger improvements in power transfer can be achieved by converting ac systems to dc, which can also adopt compact configurations as described in Technical Brochure 831.

Another, lower cost alternative is to increase the thermal rating of the overhead line by increasing the conductor operating temperature. This option is limited by ground clearance (sag or catenary) curves for many transmission lines constructed before 1940 to respect a 50°C upper limit. Meteorological loading conditions in original designs considered ice thicknesses of between 0.5 to 1.5 inches of radial ice and wind pressures, which combine with age effects to put the conductor into its “final” state, when no more creep is expected. Each span of a stringing section between dead-end towers has a unique change in sag with temperature, leading to individual maximum temperature ratings for each span. These ratings are established with confidence by extrapolating from known conductor profiles, obtained by laser equipment in a helicopter-based condition survey.

In 2002, Hydro One carried out a laser condition survey on a 115 kV double circuit transmission line first energized in 1929, and based on the results, deemed it unfit for future service. This line used 605 kcmil ACSR (54/7) and a singe 5/16” steel overhead groundwire on ST3-81 lattice steel towers. The 115 kV line was “rebuilt” by placing double circuit 230 kV lattice structures, also in Fig. 6, at each of the original 115 kV tower locations. This project set an upper bound on what can reasonably be considered as “refurbishing” from a maintenance budget.

Fig. 7 shows dimensions of twin 230 kV lines, with lattice structures of 24.7 m (81’) height in the same province, which grew to be a six-circuit three-voltage corridor in the early 1990s.

These were energized in 1932 in Ottawa, Canada when its population was 127,000. Load growth corresponding to a population of 1 million led to the extension of a 500 kV system from southwest Ontario to the Ottawa area in the period 1988-1992. Within the city of Ottawa, legacy 115 kV and 230 kV circuits were accommodated on 500-kV double circuit towers, also shown in Fig. 7. When two or more lines run on the same right-of-way, towers that have the same construction and dimensions are preferred, even if the lines are energized at different system voltages. The choice of slightly unbalanced but symmetrical structures reduces some of the visual impact of lines that now traverse residential areas. Another project added 6 m tower extensions and eliminated the bottom crossarm to increase phase-to-ground clearance by a total of 9.45 m. (Q5G / Q2AH TnD World Nov 2017)

Reduce Visual Impact
Steel lattice towers, such as those shown in Fig. 7 are elegant in an engineering sense, as they develop the desired mechanical strength for a range of normal and adverse load conditions with a minimum of weight and cost. Since the 1980s, the public has expressed an appreciation instead for tubular towers in neutral colors. Steel pole structures dominate the wind turbine installations and harmonize reasonably well with urban settings as shown in Fig. 8.

The vertical suspension insulators on the new 138 kV line in Fig. 8 allow the conductors to move from side to side, as well as along the line for partial equalization of tension within stringing sections. The older line configurations in Fig. 9 also show suspension strings.

Starting first at 735 kV center phase, and then applied to the compact monopole 315 kV designs in Fig. 10, “V” strings of twin insulators stabilize the horizontal conductor motion at the tower head. This is defined as “compact” construction because it allows a reduction in electrical clearances.

Address Right-of-Way Encroachment
In many regions, overhead lines originally situated in open terrain have supported development, including many houses backing directly on the right-of-way. In France, for example, EDF has addressed the risk of exposure to fault potential transfer from 63 kV and 90 kV systems by fitting transmission line surge arresters to directly reduce the number of faults.

References
[1] EPRI, EPRI AC Transmission Line Reference Book – 200 kV and Above, Third Edition (the Red Book), Palo Alto, CA: EPRI 1011974, December 2005.
[2] ESKOM, The planning, design and construction of overhead power lines, Johannesburg: Crown Publications cc, May 2010.
[3] CIGRE Study Committee B2: Overhead Lines, Overhead Lines, Cham, Switzerland: Springer Nature, 2017.
[4] CEATI International, “Best Practices Guide for Extra High Voltage (EHV) AC Overhead Transmission Line Design – Electrical Aspects,” CEATI Report T163700-3398A, Montreal, Canada, February 2019.
[5] IEEE, IEEE Guide for Improving the Lightning Performance of Transmission Lines, Piscataway, NJ: IEEE Standard 1243-1997, Reaffirmed 2008, September 2008.
[6] IEEE Power & Energy Society, Transmission and Distribution Committee, IEEE Standard 1410-2010: IEEE Guide for Improving the Lightning Performance of Electric Power Overhead Distribution Lines, New York: IEEE Standards Association, 2011 Jan 28.
[7] CIGRE WG 33.01, Guide to Procedures for Estimating the Lightning Performance of Transmission Lines, Paris: CIGRE Technical Brochure 63, October1991 revised 2021.
[8] CIGRE WG C4.23, “Procedures for Estimating the Lightning Performance of Transmission Lines – New Aspects,” CIGRE Technical Brochure 839, Paris, June 2021.
[9] IEEE-SA Board of Governors and IEEE Power and Energy Society, IEEE Recommended Practice for Overvoltage and Insulation Coordination of Transmission Systems at 1000 kV AC and Above, New York, NY : IEEE Standard 1862-2014, 15 May 2014.
[10] Ohio Brass Company, Lightning Performance of Typical Transmission Lines, Second Edition, Mansfield, OH: Ohio Brass Company Publication 1321-H, 1955.
[11] NERC (North American Electric Reliability Corporation), “2023 State of Reliability Technical Assessment,” 06 2023. [Online]. Available: https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/NERC_SOR_2023_Technical_Assessment.pdf. [Accessed 30 07 2023].
[12] NERC, “Transmission Availability Data System (TADS),” North American Electric Reliability Corporation, 2023. [Online]. Available: https://www.nerc.com/pa/RAPA/tads/Pages/default.aspx. [Accessed 30 07 2023].
[13] CIGRE WG 33.01, Guide to Procedures for Estimating the Lightning Performance of Transmission Lines, Paris: CIGRE Technical Brochure 63, 1991.
[14] CIGRE WG C4.26, Evaluation of Lightning Shielding Analysis Methods for EHV and UHV AC and DC Transmission LInes, Paris: CIGRE Technical Brochure 704, October 2017.
[15] NALCOR, “Island Interconnected System Supply Issues and Power Outages,” [Online]. Available: http://www.pub.nf.ca/applications/IslandInterconnectedSystem/files/rfi/PUB-NLH-177.pdf. [Accessed 30 07 2023].
[16] Newfoundland Labrador Hydro, “Uptrade Transmission Line Corridor, Bay d’Espoir to Western Avalon,” September 2011. [Online]. Available: http://www.pub.nf.ca/applications/ARCHIVE/NLH2012Capital/files/application/NLH2012Application-VolumeII-Report10.pdf. [Accessed 30 07 2023].
[17] INMR, “Looking Back on the Great Ice Storm of 1998,” 28 11 2020. [Online]. Available: https://www.inmr.com/looking-back-on-the-great-ice-storm-of-1998/. [Accessed 30 07 2023].
[18] INMR, “Experience from Application of Transmission Line Arresters in Romania,” 07 03 2023. [Online]. Available: https://www.inmr.com/experience-from-application-of-transmission-line-arresters-in-romania/. [Accessed 31 07 2023].
[19] Vaisala, “Vaisala Xweather Interactive Global Lightning Density Map,” Vaisala, 2023. [Online]. Available: https://interactive-lightning-map.vaisala.com/. [Accessed 01 08 2023].
[20] CIGRE WG B2.63, Compact AC overhead lines, Paris: CIGRE Technical Brochure 792, February 2020.
[21] CIGRE WG B2.62, Compact DC overhead lines, Paris: CIGRE Technical Brochure 831, March 2021.
[22] CTV News, “Powerline to nowhere: $100M powerline costing taxpayers millions,” Bell Media, 05 11 2015. [Online]. Available: https://toronto.ctvnews.ca/powerline-to-nowhere-100m-powerline-costing-taxpayers-millions-1.2644932. [Accessed 13 09 2023].
[23] R. Anderson, H. V. Niekerk, H. Hroninger and D. Meal, “Development and field evaluation of a lightning earth-flash counter,” IEE Proceedings, vol. 131 Part A, no. 2, pp. 118-124, March 1984.
[24] M. Peterson, D. Mach and D. Buechler, “A Global LIS/OTD Climatology of Lightning Flash Extent,” JGR Atmosphers, vol. 126, no. e2020JD033885, p. 23, 19 Feb 2021.
[25] NOAA, “GOES – East Full Disk – Geostationary Lightning Mapper,” NEDIS.STAR.Webmaster@noaa.gov, 02 08 2023. [Online]. Available: https://www.star.nesdis.noaa.gov/goes/fulldisk_band.php?sat=G16&band=EXTENT3&length=240&dim=0. [Accessed 02 08 2023].
[26] Environment Canada, “The average lightning flash density (flashes per square kilometre, per year) in Eastern Canada (1999 to 2018).,” 21 06 2016. [Online]. Available: https://www.canada.ca/en/environment-climate-change/services/lightning/statistics/maps-hotspots.html. [Accessed 13 7 2022].
[27] R. Evert and M. Gijben, “Official South African Lightning Ground Flash Density Map 2006 to 2017,” in Earthing Africa Symposium & Exhibition 2017, Johannesberg, South Africa, 5-9 June 2017.
[28] CIGRE WG C4.407, Lightning Parameters for Engineering Applications, Paris: CIGRE Technical Brochure 549, August 2013.
[29] Vaisala Xweather, “The Annual Lightning Report – Total Lightning Statistics for 2022,” Vaisala, 2023. [Online]. Available: https://indd.adobe.com/view/d0591066-471e-41b9-83e1-4dc937aaeb96. [Accessed 10 09 2023].
[30] P. Sporn, “Lightning Experience on 132-kV Transmission Lines of the American Gas and Electric Company System, 1930-1931,” AIEE Transactions, pp. 482-490, June 1933.
[31] CIGRE WG C4.39, “Effectiveness of line surge arresters for lightning protection of overhead transmission lines,” CIGRE Technical Brochure 855, Paris, December 2021.
[32] E. Tarasiewicz, F. Rimmer and A. Morched, “Transmission Line Arrester Energy, Cost, and Risk of Failure Analysis for Partially Shielded Transmission Lines,” IEEE Transactions on Power Delivery, vol. 15, no. 3, pp. 919-924, July 2000.
[33] J. Takami and S. Okabe, “Observational Results of Lightning Current on Transmission Towers,” IEEE Transactions on Power Delivery, vol. 22, no. 1, pp. 547-556, January 2007.
[34] W. A. Chisholm and S. de Almeida de Graaff, “Adapting the Statistics of Soil Properties into Existing and Future Lightning Protection Standards and Guides,” in 2015 International Symposium on Lightning Protection (XIII SIPDA), Balneario Camboriu, Brazil, 28 September – 2 October 2015.
[35] EPRI, Transmission Line Reference Book, 345 kV and Above, Second Edition, Palo Alto, CA: EPRI, 1982.
[36] A. R. Hileman, Insulation Coordination for Power Systems, New York: Marcel Dekker Inc., 1999.
[37] EPRI, Transmission Line Reference Book: 115-345 kV Compact Line Design, Palo Alto, CA: EPRI 1016823, 2008.
[38] EPRI, “Guide for Transmission Line Grounding: A Roadmap for Design, Testing and Remediation,” EPRI, Palo Alto, CA, 2004. 1002021.
[39] W. A. Chisholm, “Arrester Protection of Lower Voltage Circuits on Multi-Voltage Towers: Issues & Opportunities,” in 2019 INMR World Congress, Tucson, AZ, October 20-23, 2019.
[40] F. Rizk, “Negative Impulse Ground Wire Corona Parameters for Backflash Evaluation of High Voltage Transmission Lines,” IEEE Transactions on Power Delivery, vol. 37, no. 4, pp. 2474-2481, August 2022.
[41] F. Rizk, “Novel Solution to Back Flashovers on High Voltage Transmission Lines: The Embedded Ground Conductor,” IEEE Transactions on Power Delivery, vol. 37, no. 6, pp. 5345-5355, December 2022.
[42] W. Chisholm and W. Janischewskyj, “Lightning Surge Response of Ground Electrodes,” IEEE Transactions on Power Delivery, vol. 4, no. 2, pp. 1329-1337, April 1989.
[43] J.-F. Goffinet, “Design & Erection of Insulated Cross-Arms,” 07 01 2022. [Online]. Available: https://www.inmr.com/design-erection-of-insulated-cross-arms/. [Accessed 10 09 2023].
[44] CIGRE WG B2.56, Ground Potential Rise at Overhead AC Transmission Line Structures during Power Frequency Faults, Paris: CIGRE Technical Brochure 694, 2017 07.
[45] L. Grcev, B. Markovsi and M. Todorovski, “Lightning Efficient Counterpoise Configurations for Transmission Line Grounding,” IEEE Transactions on Power Delivery, vol. 38, no. 2, pp. 877-888, April 2023.
[46] W. A. Chisholm, “Evaluation of Simple Models for the Resistance of Solid and Wire-Frame Electrodes,” IEEE Transactions on Industry Applications, vol. 51, no. 6, pp. 5123-5129, November/December 2015.

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Moderately elevated temperatures can be caused by proximity to fires, electrostatic precipitators and induced magnetic fields or even by simply exceeding a line’s current ratings. Operating conditions of a utility also play a role since conductors can attain elevated temperatures during line over currents. Inductors and coils can induce magnetic fields that heat metal parts to from 150°C to 200°C.

Insulators are designed to operate within the normal temperature ranges of the equipment they support. It is therefore not expected that they withstand extreme elevated temperatures without damage, i.e. mechanical and dielectric strength can be reduced depending on event and temperature. Utility equipment will therefore need to be inspected for possible damage and urgency for maintenance or replacement. While insulators that sustain severe damage are typically easy to detect, those with less noticeable damage can sometimes go undetected.

This edited past contribution to INMR by Patrick Maloney of PPC Insulators discussed the effects of elevated temperature on ceramic insulators as well as relevant points to consider. Construction design and how heat is applied all play a role.

EMCO Industries

Pakistan

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Canada

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Materials

Although pin, spool and strain insulators are made solely of ceramic material, most porcelain insulators consist of a combination of materials, including the ceramic insulation, fixing metal parts, bonding cement and expansion coatings. Each material responds to heat in different modes. The ceramic material and iron fittings can withstand temperatures well above normal operating conditions. For example, ceramics can be re-fired at temperatures reaching 1300°C for repairing glaze before assembly. Cast iron can withstand 650°C, as per ASTM A278-53, and hot-dipped galvanizing will melt at 419°C. More limiting materials include the portland cement and the bituminous asphalt used for expansion joints. Bitumen begins to melt at 115.5°C (e.g. PPC Insulators uses 75°C.) At this point, the bitumen will lose mechanical strength and could potentially liquefy and run out of the hardware. Portland cement can lose mechanical strength due to factors such as temperature level, heat rate, duration, type of aggregate, solo vs. cyclic thermal event and whether or not the cement is confined.

Construction

An insulator’s design contributes to how it is affected by heat. In the case where insulators consist of metal fittings and a ceramic body, fittings are attached using Portland cement. Modern ceramic station post insulators are constructed with metal fittings external to the porcelain whereas cap & pin post insulators of the past were constructed with the mounting pin internal to the porcelain. Thermal expansion will affect each differently.

Thermal Expansion

The key components of a ceramic insulator, namely the ceramic insulating body, the metal fixing fittings and the Portland cement all have different coefficients of thermal expansion:

Iron: 11.5

Portland cement: 10.0

Porcelain: 5.7

Shape also influences how an object will expand under heated conditions. A thin rod, for example, will expand far more in length than in diameter. Similarly, a thin-walled tube will gain circumference and thus diameter. A thick-walled tube will experience expansion in circumference and wall thickness.

Insulators with external metal hardware will not induce compressive forces under elevated heat. The thermal expansion of metal fittings is greater than that of Portland cement and porcelain. Moreover, the Portland cement’s expansion is greater than of the porcelain. In a reverse scenario, where an insulator has internal fittings, the cement would be under high compressive forces resulting in possible damage to the structure.

Heat Exposure Modes 

There are varying conditions under which an insulator can become exposed to heat. In the case of fire or an arc flash, the heat is applied at a high rate followed by a natural cooling cycle. The heat source could be unbalanced, e.g. in the case of an arc flash that causes sheds to crack and glaze to melt. Arc flash events produce very high temperatures but have very short duration. Long duration heat sources are those that occur over many hours or days and where the entire insulator location remains at the same temperature. Elevated temperatures can be from a single event or cycled over time.

Analysis After Elevated Heat Exposure

Extreme Heat 

In the case of a power arc flash, damage can be clearly seen due to the extreme heat of 19,000°C. The glaze can become darkened and blistered. Events with arc durations that exceed normal protection equipment’s clearing/interruption time of 5 -16 ms can cause some sheds to shatter. This is due to the isolated heating causing thermal expansion at the thin area of the sheds.

Ceramic station posts are made of high-density materials and are slow to heat. Most of the damage will be external for easy visual evaluation. Blistered glaze has a rough surface that will collect contamination over time. Sheds lost to shattering will also reduce creepage distance. Still, exposed unglazed ceramic areas are not affected by water ingress due to the lack of porosity of well-fired ceramic materials. Blistered glaze or missing shed conditions is not an immediate concern if the damage is limited to less than 10% of the surface and does not extend to the core of the unit. Insulators with such damage can be replaced whenever convenient.

Moderate Heat Exposure

Historically, overhead lines have shown a low threshold for heat exposure. For example, heated conductors will sag more, creating clearance issues. Aluminum can be annealed, losing strength. Overhead conductors such as ACSR, AAC and AAAC have a maximum operating temperature of 100°C. More modern conductor options including ACCR, ZTACIR and ACCC, have much higher temperature ratings, i.e. 180°C to 250°C. At such high temperatures, polymeric insulators become vulnerable to damage.

Analyzing ceramic insulators exposed to more moderate temperatures of 100°C above normal design limits can pose challenges. A typical temperature limit for equipment in a substation would be 105°C and 65°C above a 40°C ambient baseline. Moderate heat exposures can be caused by over currents, proximity to electromagnetic fields, substation fires or nearby wildfires.

With exposure from moderate to high elevated temperatures, the focus shifts to the cement. Ceramic and iron materials can withstand 200°C indefinitely but Portland cement will lose strength given prolonged exposure to 100°C or higher. Several variables and combinations of conditions will influence level of degradation.

The goal of this research was to investigate realistic elevated temperatures that might or might not cause catastrophic failures soon after an event. A cap of 400°C was defined as the upper end. Note that 400°C is approximately four times the typical temperature limit for insulators. With the Portland cement identified as the critical material, thermal testing was needed to better understand the rate at which strength is lost. Testing was performed on assembled insulators, i.e. with cement and metal fittings.

Test Approach & Summary

Tests were conducted to determine the temperature exposure and duration at which cantilever strength is reduced. The first steps were exploratory in order to establish the region or range at which changes in cantilever strength might be observed. For example, past such studies have shown that insulators exposed to 200°C for 4 hours exhibited little reduction in cantilever strength. Here, the testing began at 300°C and increased or decreased to a find a threshold temperature. Temperatures above 400°C were deemed beyond the scope of this study.

Groups of 5 insulators were exposed to different temperature cycles, with a maximum of 400°C. Initial duration of heat exposure was set as 4 hours. The samples were then subjected to cantilever testing per ANSI C29.1 Clause 5.1.3 in order to determine strength loss compared to the control group. The insulator samples selected for study were ANSI C29.7, 57-2 line posts with heights of 305 mm, diameters of 146 mm and a cantilever rating of 12.5 kN.

The lab oven, measuring approx. 500 mm by 500 mm and with height of 460 mm, has a maximum heat capability of 1200°C. Five samples were placed inside for each experiment.

The bending equipment met the required force of 18 kN and was capable of a center mount stud utilizing a ¾-10 UNC oversized thread. This equipment could apply a precise load rate within the bounds of ANSI standard C29.1. The load was applied rapidly up to 75% of rated cantilever strength, i.e. 9.3 kN. The remaining load was applied at a rate of 45% of rated cantilever/min, until yield.

Ten insulators were subjected to cantilever yield levels to establish a control group. Each temperature exposure test group consisted of 5 samples.

Expected cantilever strength reduction for the 4-hour exposure would likely fall between 150°C and 400°C. The first round of heat exposure testing was at 300°C for 4 hours. Once cooled to room temperature, each set was tested to cantilever yield level within 24 hours. The data was then reviewed to determine temperature levels for subsequent testing.

The expected cantilever strength reduction for the 12-hour exposure would fall between 200°C and 400° C. The first round of heat exposure tests was at 300°C. Again, each sample lot consisted of 5 units. Once cooled to room temperature, each set was tested to cantilever yield level. Data was reviewed to determine temperature levels for additional tests.

Test Findings & Discussion

Average cantilever strength of the control group was measured at 14.30 kN, with standard deviation of 2.34 kN.

The first group of insulators was exposed to 300°C for 4 hours. average cantilever strength was measured at 14.33 kN, with standard deviation of 1.77 kN. The second group was exposed to 400°C for 4 hours. Now, average cantilever strength was measured at 14.85 kN, with standard deviation calculated at 2.49 kN. The third group saw the test duration increased to the upper limit of 12 hours. Temperature level was 300°C and average cantilever was found to be 15.46 kN, with standard deviation at 1.03 kN.

The test of the final group involved maximum temperature of 400°C and longest duration, at 12 hours. Average cantilever strength was found to be 13.12 kN – a decrease of 8% compared to the control group. Standard deviation of findings increased to 2.68 kN.

Conclusions

Ceramic insulators are typically rated for 105°C. Power arcs and direct exposure to wildfires will almost certainly destroy all equipment. By contrast, moderate to extreme conditions such as found in proximity to wildfires, near substation fires and from over currents can also subject insulators to temperatures well above their ratings. While some damage may occur, the insulators can remain in service pending further analysis.

This research has demonstrated that ceramic insulators are robust and resilient to moderate elevated temperature exposure. Future studies in this area are planned to also include cycle bending loads.

STRI

Sweden

PSW – Siemens Energy Testing Laboratories Berlin

Germany

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The post Ceramic Insulators Under Elevated Temperatures appeared first on .

To perform the test, the cable system was energized with a resonant test set to 330 kV for a period of 60 minutes. Three teams of technicians simultaneously measured PD at different cable joints using high-frequency current transformers (HFCTs) and mobile PD test equipment in a process referred to as ‘joint-hopping’.

Selection of appropriate measurement frequencies and verification of sufficient sensitivity are discussed and results analyzed.

Klöckner Desma Elastomertechnik GmbH

Germany

RHM International

USA

See more suppliers of Laboratory & Field Testing Equipment

High voltage (HV) cable systems are the backbone of energy networks around the globe. While their purchase is costly, the installation and required civil works can be even more expensive. Full turnkey projects for long lengths of HV or EHV cable, installation, civil works, substations and associated needed infrastructure can exceed $1 billion. Once installed and energized, HV and EHV transmission class cables are typically critical assets for the energy grid and must not fail in service. To assure proper production, installation and life cycle management of such assets, the IEC, IEEE and CIGRE have all issued multiple Guides, suggestions and standards – all requiring proper testing of HV cables.

Before HV & EHV cables and cable components leave the factory, they must undergo a series of tests to ensure that they meet contractual specifications, which are often based on the aforementioned standards and guides. Some tests are designed to check the mechanical integrity of the cable conductor, the dimensions and multiple parts of the extrusion process during manufacturing.

To test the insulation of the cable, HV testing with voltages exceeding rated operating voltage (U0) combined with Partial Discharge (PD) measurement are widely used. These tests shall assure that no life limiting production-related damage or impurities are present in the insulation of the cable system.

Successful testing in the factory requires trained personnel and adherence to cable factory testing standards. Ideally, these tests are carried out in a controlled environment such as shielded rooms to reduce external background noise. However, even the most rigorous factory testing cannot guarantee that the cables will be installed correctly or that they will not be damaged during transport or laying.

Once cables are delivered to site and installed, most future owners require commission tests before accepting ownership. Such tests are designed to detect possible damage that might have been inflicted during transport or laying. Special focus lies on the accessories, which are often installed in the field under conditions that are far from the clean, shielded room conditions of factory setups. In fact, the primary purpose of on-site testing is to detect possible issues in the cable system resulting in limiting life.

According to CIGRE studies based on a population of 26,494 km of HV and EHV cable tested with AC (20 Hz – 300 Hz), only 0.01% of the cables systems showed non-passing issues in the cable sections themselves. However, the non-pass rates for terminations and joints were 2.8% and 0.75% respectively.

For on-site testing, overvoltage tests above nominal voltage phase-to-ground (U₀) and in combination with PD testing is now state-of-the-art. IEC and CIGRE both state requirements in regard to voltage levels and setup of PD measurement equipment. These requirements are rigorous to assure proper testing of HV cable systems to avoid both false positive and false negative test outcomes. Often, the parties carrying out the on-site tests follow such requirements, particularly in regard voltage levels and test durations.

To energize HV and EHV cables, especially with elevated voltages, huge and expensive generator-transformer test sets would be needed. Their size and weight would put many challenges in the project management involved in the testing. Therefore, to reduce the size and weight of the voltage sources for such a commissioning test, mobile, modular Resonant Test Systems (RTS) are often used to energize the cables. Many HV RTS usually have a fixed inductance. Together with the capacitance of the cable system, a resonance circuit is established and by means of tuning the frequency, the resonance frequency between 20Hz and 300Hz is being established as per Clause 16.3 of IEC 60840 and IEC 62067.

The longer the cable system at a certain voltage class, the greater the capacitance and resistive losses in the cable system under test. For long cable systems, such as the 22 km cable system described here, multiple RTS need to be used in series and parallel to drive the needed current and therefore voltage for the overvoltage tests.

IEC and CIGRE state clear requirements concerning the PD measurement, required sensitivity, maximum allowable PD from a cable system and thus the maximum background noise. These requirements are justified and are important to achieve. Unfortunately, for long cable systems, these requirements are seldom met, especially the demands for background noise. Even with state-of-the-art PD test systems, obtaining a background noise of less than 5pC can be challenging to impossible, based on the surroundings of the test area. For the time being, the only way to conduct PD measurements is by trying to reduce background noise and varying the PD measurement frequencies (center frequency) by assuring proper sensitivity at the same time.

Challenges of PD Measurement for Long HV Cable Systems

The primary challenge of PD measurement for long HV cable systems is the high attenuation of the PD signals and, as well, further magnitude deterioration at accessory/cable interfaces. This attenuation is caused by the resistance, inductance and especially capacitance of the cable and increases with cable length. As a result, the PD signals that reach the PD measurement sensors are weaker than for a shorter cable. This can make it difficult to detect and measure PD signals, especially at low levels. Even low levels of PD can indicate issues within the cable insulation and can lead to severe and even catastrophic failures with danger to assets and safety.

Another challenge is the potential for interference from external sources. In general, the cable acts like an antenna for airborne noise. The longer the cable, the better the antenna function. Interference can come from a variety of sources including power lines, other electrical equipment regulated by power electronics such as rotating machines, wireless networks, and even the grounding network. It can be especially important to filter out interference when possible PD signals are weak.

Test Setup

Cable System
The cable under test is specified as a 230 kV / 400 kV cable with U₀ = 220 kV and U_max = 420 kV with a length of 22 km and a copper conductor with a minimum diameter of 2500 mm². Each phase of the 3-phase cable is sectionalized by 33 joints thus creating 34 cable sections. Open-air end terminations are installed at one end of the cable. On the other GIS end terminations are present. The end terminations at both sides are grounded directly.

What Cable End to Energize From?
CConnecting an external voltage source such as an RTS to a GIS is possible by means of special adapters that require trained personnel to be connected correctly and must also be handled with care. Moreover, they have an economic impact on testing costs. While these costs are small in relation to the total project cost of the cable installation, they can become a significant factor in relation to the cost of commissioning testing by itself.

Testing through the GIS would result in the energization of more parts of the GIS system than the cable terminations only. These additional parts often have current transformers (CTs) or voltage transformers (VTs) installed that have stricter limitations concerning possible overvoltage and testing voltage frequencies. Depending on manufacturer of the GIS and CTs and VTs, the testing voltage frequencies are usually limited to 50 Hz to 80 Hz. This is a significant difference to the aforementioned 20 Hz and 300 Hz (IEC 60840 and IEC 62067) for cable testing.

These limitations would increase number of RTS systems needed since more power would be necessary to bring the resonant frequency up to 50 Hz – 80 Hz rather than slightly above 20 Hz. This increases complexity of the HV voltage source setup and therefore testing costs. Thus, it was decided to energize the cable from the open air end termination side.

Joints
In each phase, 33 joints connect the 34 sections of the cable to each other.

The individual cable sections between the joints vary from 610 m to 700 m. At every third joint bay, the cable sheaths are grounded. For the other joint bays, cross bonding is installed with over-voltage arresters towards ground.

Measurement Setup
Long AC high-voltage (HV) cables are installed with cross-bonding joints to reduce circulating currents in the cable screens. During AC commissioning testing of each phase individually, the cross-bonding configuration of the cable screens must be inactive and a straight-through cable screen configuration must be established. These configurations are often done in link boxes, which can be accessed from above. Sometimes these link boxes are above ground, but are often located in manholes or just below the surface in joint bays, referred to as ‘coffin boxes’.

HFCT
Link boxes provide easy access to the screens of the joints and often allow for the easy installation of High Frequency Current Transformers (HFCTs). HFCTs are non-invasive sensors that can be clamped around the cable screens to detect PD signals. The main advantage of placing HFCTs in link boxes is their proximity to the joints. This allows for the detection of PD signals with high sensitivity and accuracy.

In a factory environment, where individual cable reels and accessory components are tested, coupling capacitors are typically used to measure PD signals, as stated in the IEC 60270. This is so because the test objects in a factory environment, largely, behave like lumped capacitances. Coupling capacitors are connected in parallel with the cable conductor and provide a path for the PD signals to flow to the measuring equipment. However, coupling capacitors are not feasible for long cable systems since (1) these constitute distributed impedances and (2) are subject to attenuation of high frequency signals such as PD.

Cigre B1.28 states: “For shorter lengths of cable systems, terminal PD measurements can be performed, whereas for longer lengths of jointed cable systems a distributed PD measurement should be performed.” [1] This means that for long cable systems, it is important to measure PD signals at multiple locations (joints) along the cable length.

HFCTs are often the best sensors for distributed PD measurement because they are non-invasive and can be installed at any location along the cable route without the need to include PD sensors in the joints themselves.

Center Frequencies Setup
Many PD measurement systems allow the operator to determine the center frequency for each sensor. The main goal of such setting is to ensure proper PD signal reception and the proof thereof. To reduce the background noise, changing the center frequency can be helpful too, as long as it can be assured that PD signals are not missed.

The ultimate goal is to a good signal to noise ratio (SNR), with a high decoupling of possible PD signals and low background noise. Unfortunately, the background noise can be different at every joint position.

The center frequencies for the PD measurement should be chosen with care based on the setup and used sensors. Some users have the tendency to view the manufacturers transfer function of a given sensor and assume this will be the frequency response of the total measurement system. Sometimes they even perform what many people call “calibration” before arriving on site.

Using a calibrator to inject a signal into the HFCT is a sensitivity check, but should not be mistaken with a calibration according to the IEC standards for factory measurements on cable components or short cable lengths. For this case it must be noted, that for long lengths of cables, the cable system does no longer act like a lumped capacitance and the assumptions in IEC 60270 is no longer meaningful.

A sensitivity check of the HFCT will give the scale factor that can be used to convert the output of the HFCT to the actual PD magnitude. This scale factor is described as k in the IEC 60270. This scale factor is valid for the selected testing center frequency and bandwidth. It will most likely stay within +/- 5% for another HFCT of the same model.

In Fig. 4, the blue line represents an almost ideal transfer function of an HFCT. Operating the HFCT in the frequency range where the blue line is horizontal would be optimal, as the scale factor of the HFCT would the constant – at least in theory.

With the green line representing the FFT of the noise, the difference between the blue and the green line would be the Signal-to-Noise Ratio (SNR). Clearly, the higher the frequency, the higher the SNR. This can be illustrated in the following real background noise measurement at site.

Fig. 5 shows the background noise at 2 different center frequencies using the same scale factor (around k =5). Sometimes this leads to the misconception that the center frequency should be very high to obtain a good SNR or even that the center frequency can be chosen at will as a low background noise is supposedly the most admirable goal during test. Sometimes there is the attempt to change the center frequency at every joint to obtain the lowest background noise. Such procedure neglects the fact, that the HFCTs, the cable leads from the joint to the link boxes and the cable system itself, just to name the most important ones, create a complex network of impedances.

Such complex network will result in a frequency response that does not resemble the blue line in Fig. 4. The effective frequency response can show multiple resonance frequencies that affect sensitivity of the PD measurement at different center frequencies. When viewed in the frequency spectrum, there will be frequencies with high attenuation and frequencies with high amplification.

Fig. 6 shows an exaggerated plotted example of multiple resonance frequencies. It shows multiple areas of amplification and attenuation combined with attenuation towards higher frequencies. The attenuation towards higher frequencies is symbolic of the attenuation of signals along the cable.

If the measuring center frequency is set to a position where there is a lot of attenuation/damping visible in the spectrum, the background noise may appear to be low. Inexperienced persons might conclude that this frequency is ideal for getting close to the desired background noise level of less than 5 pC, as suggested in IEC and CIGRE. This is sometimes emphasized by the fact that the scale factor k of the HFCT at this frequency is similar to other center frequencies that are +/- 1MHz. Unfortunately, at a minimum of a resonance frequency, not only is the background noise low but the ability to detect PD from the cable system can also be close to zero. Conversely, there will be center frequencies where the PD setup will show high responses to high-frequency signals. In these areas of the frequency spectrum, the PD return is high but the background noise is high as well.

Fig. 7 shows an example of two selected measurement center frequencies with their respective bandwidths in a spectrum with resonances. The red center frequency will return only a small amount of energy from the cable system. Thus, the background noise will appear to be low but possible PD signals will also be very low. It is important to understand that the possible resonances in the frequency spectrum shown in Figs. 6 and 7 are the result of the aforementioned complex network of the chosen sensor, the physical location of the sensor, and the cable system under test. Therefore, these frequencies cannot be determined before arriving on site. They can only be determined once the HFCTs are placed at the cable system in multiple joints.

Often, the available time planned for the commissioning test is limited and cable installers and the owner push for rapid completion of the test. Moreover, it is in the economic interest of many parties to finish testing quickly. This pushes testing engineers to limit the number of center frequencies used at each measurement point, such as a joint bay.

If the PD testing setup in combination with the cable under test has resonance frequencies that are powerful enough to limit the measurement of PD at certain test locations, it can be difficult for the test engineer to determine this. The best possibility is to inject powerful non-classic calibration signals at one end of the cable system, having a variety of rise-times, pulse widths and fall times, measure this calibration signal at all testing points, such as the joints.

However, with cables above a couple of kilometers in length, this will be difficult since long lengths of jointed cable circuits constitute a distributed network of impedances. Therefore, conventional PD measurement, including conventional calibration, do not apply to measurement of PD on such circuits.

High Center vs Low Center Frequencies
The ability to detect calibration signals injected at one end of the cable is limited by attenuation of the signal, presence of noise and resonance frequencies of the cable system. Lower center frequencies (e.g. much below 3 MHz) allow for longer detection distances but this also increases amount of background noise. This is because both the PD signal and the background noise are attenuated by the cable. But the PD signal is attenuated more quickly – at least it seems that way. As a result, a PD signal becomes more difficult to distinguish from the background noise at lower center frequencies.

For center frequencies above 3 MHz or 4 MHz, the calibration signal can only be detected a few joints down the cable and in some cases even less depending on the design of the cable system. As a rule of thumb, the higher the center frequencies, the more localized the measurement will be around the test position (e.g. joint), thus reducing the “ability” of the HFCT to detect signals from larger distances.

Choosing higher center frequencies can be beneficial in the presence of high noise sources. Partial discharge from the HV source setup can be the origin of noise, especially if it cannot be mitigated properly. On long cables, these high center frequencies will make it difficult to detect the calibration signal over multiple joints and to ensure that any resonance frequencies in the setup are identified.

Selecting Proper Center Frequency
One way to ensure proper center frequency selection is to test at multiple joints simultaneously. This can be done by injecting a calibration signal through the HFCT at one joint bay and verifying that the signal can be detected at neighboring joint bays. The HFCT is positioned around the sheath cable at the link box in the same way that it will be positioned to test for PD. A wire loop from the calibrator is either threaded through the HFCT, as in the sensitivity check, or the HFCT is directly connected to the calibrator using a short 50 ohm coaxial cable.

If this procedure is repeated for different joints, the attenuation of the cable under test can be recorded for all center frequencies being used. This information can then be used to select the best center frequencies for PD testing. Of course, for such procedure multiple test teams need to work in parallel on neighboring joints.

It is important to note that PD testing on HV or EHV cable systems typically involves scanning for PD over a range of frequencies. This makes is easier to distinguish possible PD from noise source and localize these PD.

Voltage Source Setup
According to CIGRE TB 841 and TB 728, the cable system shall be without PD at 1.5 * U₀ = 1.5 * 220kV = 330kV.

The used Resonance Test System (RTS) can energize a cable up to a testing voltage of 260 kV with a current of 70 A – 90 A. The longer the cable, the higher the capacitance. For longer cables, often 2 or more RTS need to be used in parallel to feed enough current to provide sufficient recharging current.

For cable tests above 260 kV, RTS need to be used in series, with the second reactor on insulators to reach voltage of around 520 kV. For this commissioning test, extra reactors are needed to elevate the voltage up to 330 kV, as required by CIGRE.

The RTS uses an adjustable frequency to tune to the resonance frequency in an LC network. The inductance (L) is part of the test system and the capacitance (C) is represented by the cable. Due to the cable’s length, the capacitance totals about 5000 nF, according to the specification sheet.

To drive enough current to energize the 22 km cable, four RTS units must be connected in parallel, with aforementioned extra reactors on insulating stands.

With 4 RTS and additional 4 reactors, the voltage source setup alone requires multiple technicians for minimum a day. The 4 RTS need to be synchronized with all voltage taps on the exciters being correctly set. This system needs to be connected to multiple diesel generators working synchronously as well to supply enough feeding power.

The HV connection from the voltage source to the test object is very challenging and takes multiple days to set up properly. A major challenge is the wind, which picks up sand and proximity to water. The combination of humidity, especially in the morning, and fine sand is highly challenging as dust settles on the conductors of the setup.

Due to the space required for the voltage systems, as well as the space needed to manoeuvre the trailers and diesel generators, in this case it was not possible to set up close enough to the cable under test. Instead, the setup was placed about 120 meters away, as shown in Fig. 10.

Under these conditions, it is economically difficult to create a setup that does not show any external discharges since this would take many days to set up and large investments in proper insulating stands. The current setup (Fig. 10) will result in PD during the measurement at the near end of the cable and thus properly interpreting the data requires expertise and skill. For the above testing project, the end client understood the issue and agreed to a commissioning test under these conditions.

Measurement Procedure

Testing a 33-joint-bay HV cable system with 2 end terminations can be a challenging task. One of the key challenges is that it is not feasible to test at all locations simultaneously. This is because fiber optic cables are not available to connect the joint bays. In this case, a ‘joint-hopping’ approach can be used.

The following procedure was agreed upon with the end client:
– Perform a 1-hour withstand test.
– If the HV AC withstand test is successful, perform “joint-hopping” with 3 teams and energize for PD tests

This will expose the cable to a longer duration of energization above U₀, but is more economical than deploying 35 PD measurement units with an operator each and testing them simultaneously.

In this joint-hopping approach, three teams are deployed to different joint bays. Each team is equipped with an HFCT, a calibrator, and a PD measurement device. The teams then connect their HFCTs in the link boxes and perform a sensitivity check at different center frequencies. After injecting calibration signals at the near end of the cable and at different joint bays, while measuring the calibrator signals at multiple joint bays simultaneously, the team decided to use 3 MHz and 8 MHz as the center frequencies, each with a bandwidth of 650 kHz.

The distance between the teams varied during testing since the cable was not along a single street. Instead, it crossed multiple streets, quarters and areas with varying levels of population and traffic. Mean distance between two joint bays was around 650 m, but the traveling distance from one joint bay to another could vary in the city from 3 minutes to over 1 hour, depending on routing and traffic.

Access to the joint bays was often next to roads and on sidewalks but sometimes on the road itself or in parking lots. Occasionally, cars were parked on top. If their owners could not be found within 15 minutes, the team would move on to the next joint bay. If at least two teams were ready to test PD at the joints, the cable was energized for about 5 minutes to 330 kV. During that time, one measurement was taken at 3 MHz and one at 8 MHz for a minimum of 1 minute each.

Measurement Results

Sensitivity Check
The sensitivity check was performed for 3 MHz and 8 MHz for all HFCTs by running a calibrator cable through the HFCT to determine the k factor. For both center frequencies and all HFCTs the k factor was around 5. This was expected, as the transfer function of the used HFCTs is almost linear in that area (see Fig. 4 as example).

Measurement of Partial Discharge (PD) Signals
The IEC 60270 standard defines how to calculate the charge value (Q) of repetitive partial discharges. The utilized measurement system shows the Q_IEC value for the last PDs in a screenshot. Usually, this value is used to describe the discharge values of PD or background noise respectively.

The sensitivity check does not constitute a calibration procedure according to IEC 60270 nor are chosen center frequencies of 3 MHz and 8 MHz within the recommended range. As such, the measured charge values will not be described as “Q_IEC” values. The measurement system calculates the charge by the same principle, but the value is called Q weighted (QWTD) instead.

Verification of Measurement Center Frequencies
One way to ensure that all possible PD in a cable system can be detected is to assure that sensors at each joint are able to detect signals from the respective adjacent joints if the signals are well above background noise. A calibrator signal with 100 pC was injected at three neighboring joints simultaneously, in this case joint bay 5, 6, and 7. The PD measurement at each joint was recorded.

Fig. 11 shows the PRPD at joint 7. At 100 pC the calibrator signals from joint 7 can be seen as 6 dots within the 20ms time frame of the PRPD. This was the signal to determine the k factor. Also the calibrator signal from joint 6, around 650 m away, could be detected at around 4 pC, and the calibrator signal from joint 5, around 1300 m away, could be detected at around 1.8 pC. This shows that with the chosen measurement center frequencies it is possible to detect PD from adjacent joints, even over relatively long distances.

Figs. 12 and 13 show seven phase resolved partial discharge diagrams (PRPDs) each, from the end termination to joint 28, with both used center frequencies of 3 MHz and 8 MHz. The PRPDs show massive external discharges with different patterns, which were created by the long and disadvantageous HV source setup (as shown in Fig. 10). The external corona discharge signals are attenuated over distance, reducing the detectable and calculated charge value from joint to joint.

When utilizing a higher center frequency, a higher part of the signals frequency spectrum is measured. Especially on long cables, higher frequencies are attenuated more strongly than lower frequencies. This results in a stronger attenuation for the measurement with 8 MHz in relation to the measurement with 3 MHz.

In Fig. 12 the corona discharges are still visible above background noise after 6 joints, around 3.9 km respectively. With 8 MHz, the corona discharges are barely visible after 4 joints, around 2.6 km.
In both cases, it is clear that the sensor at a certain joint is able to detect PD signals from adjacent joints, if the PD are well above background noise and of sufficiently low frequency content at the point of origin to propagate in a detectable manner to adjacent accessories.

In comparison with the calibrator signals in Fig. 11, one could assume that calibrator signals attenuate stronger than PD signals. The reason for this effect lies in the way, the calibrator signals were couples into the cable.

When a calibrator signal is injected into an HFCT, only part of the energy will couple into the cable screen. This already reduced energy will travel in both directions, roughly halving the energy again. This even smaller signal will be attenuated while traveling to the next joint, where it can be picked up by another HFCT.
Different signal propagation paths of PD signals within the cable system also explain the difference of the PRPD of the end termination and joint bay 33 in Figs. 11 and 12.

Part of the energy of the external corona discharge created at the HV setup will travel towards ground at the end termination. This part can be detected by the HFCT connected to the cable screen ground at the end termination. Based on the impedance of this ground, different parts of the signal’s spectrum behave differently.

The ”other” part of the corona discharge signals energy will travel “into” the cable and propagate along the cable to the adjacent joints and can be detected at the joint bays.

The different behaviour of propagation of different frequency contents gives the impression, that for 3 MHz the corona discharge is higher at Joint Bay 33 than at the end termination where the signals are created. This is not the case. The PRPD symbolize the split up of the discharge energy, with one part going directly to ground and the other part “into” the cable.

For 8 MHz, the discharge values at Joint Bay 33 show smaller values than for the end termination. Either a larger part of the relevant frequency spectrum travelled towards ground at the end termination, or the attenuation of that part of the frequency spectrum is already dominant enough to reduce the measured and calculated charge values at Joint Bay 33.

It is important to note that the energy levels associated with externally occurring corona are higher than those typically associated with internal PD occurring within an HV or EHV cable accessory. Signals created by internal PD will be less powerful and will not be visible over multiple joints and distances of over 3.9 km, at 3 MHz for this cable testing setup. Thus, it was not possible to assess, if internal PD occurred at the end termination and the first couple of joints. Testing from the other end of the cable was not feasible due to aforementioned reasons.

The future owner of the cables system was aware of the situation. Based on the fact that the cable system was energized well above U0 multiple times and was able to withstand the elevated voltage stress without failure, the cable was later tested with U₀ and permanent monitoring for multiple days before being put into service.

GCC Electrical Testing Laboratory

Kingdom of Saudi Arabia

Powertech Labs Inc.

Canada

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Summary

Long cables do not behave like a lumped capacitance. As such, the calibration procedure according to IEC 60270 is not feasible. When testing PD on joints, the transfer function of the HFCT sensor used do not represent the frequency response of the full PD measurement setup.

The full PD measurement setup, a combination of the cable under test + the sensors + leads to the sensor + location of the sensors creates a complex network of impedances. These impedances are cause for a unique signal response.

Measurement center frequencies can not be pre-selected but must be determined at site to assure in a cross-check, that PD signals, or at least calibrator signals, from adjacent joints can be detected.

Joint hopping can be a form of testing long cables. This should be executed by multiple teams at the same time to perform the cross-check.

PD signals will attenuate over distance travelled in the cable. The higher the chosen measurement center frequency, the higher the observed attenuation of signals.

References
[1] CIGRE TB 728, May 2018, B1 Technical Brochure: “On-site Partial Discharge assessment of HV and EHV cable systems “, WG B1.38
[2] CIGRE TB 841, Sept. 2021, B1 Technical Brochure: “After laying tests on AC and DC cable systems with new technologies”, WG B1.38
[3] IEC 60270, 2015, “High-voltage test techniques – Partial discharge measurements”
[4] IEC 62067, 2006, “Power Cables Above 150 kV and their Accessories for Rated Voltages Above 150 kV (Um = 170 kV) up to 500 kV (Um = 550 kV) – Test methods and requirements”
[5] M. Fenger J. Levine, “Sensitivity Assessment for HV & EHV Field Partial Discharge Measurements via Laboratory Testing”, IEEE Conference Record of the 2008 International Symposium on Electrical Insulation, June 2012 
”
[6] N. Oussalah, Y. Zebboudj & S. A Boggs, “Partial Discharge Pulse Propagation in Shielded Power Cable and Implications for Detection Sensitivity”, IEEE Electrical Magazine, Vol 23. Issue 6, pp.. 5 – 10, Nov/Dec 2007.

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A history of repeated outages affecting the 500 kV Xingó-Angelim II Line in northeastern Brazil offers a good example of these types of issues. In this case, key factors such as changes in local precipitation patterns have meant that insulators on this line must endure longer periods with little to no natural washing. Indeed, in spite of studies on natural pollution in the areas through which the line runs, problems only intensified, in parallel with growth in the regional transmission grid.

This edited past contribution to INMR by engineers at Transmissora Aliança de Energia Elétrica S.A. (TAESA) presents experience with resolving flashover outages along this asset to avoid stresses on line and substation components and maintain reliability.

DALEKOVOD OSO

Croatia

Guangzhou MPC Power International Co. Ltd.

China

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The 500 kV Xingó-Angelim II Line runs 193 km through northeastern Brazil, connecting the Xingó Hydroelectric Plant in Alagoas State to Angelim II Substation in Pernambuco. Since commissioning in 2004, the line has suffered a series of shutdown events concentrated mainly in the São Pedro Mountains in the highlands of Pernambuco. This is a region characterized by limited precipitation, typically only from April to August, as well as frequent fog and mist. About 57 km of the line, i.e. the section from Towers #284 to #397, passes through this area (Fig. 1).

The first measure taken to resolve the problem was systematic live line washing of the line’s glass insulator strings. However, the cost of this maintenance operation soon proved untenable given the difficulty accessing towers and the short time required between successive washing cycles. In 2007, a decision was made to apply RTV silicone coatings onto the glass insulators. About 13,800 insulators were replaced with new ones of which more than 8,650 had been pre-coated.

Nevertheless, only 3 years after application of the new silicone coated insulators, another pollution flashover outage occurred at Tower #284 – located near the start of the line section marked by hills. That incident gave the O&M Engineering Team the opportunity to remove and examine the condition of the coated insulators. After only a few years in service, there was already clear evidence of surface flaking and also loss of hydrophobicity, with consequent reduction in coating effectiveness. In 2015, following further outages, Tower #284 was affected yet again, indicating the need to consider alternative measures to mitigate the problem.

Review of Operating Data

TThe O&M Engineering Team conducted studies to evaluate possible solutions, taking account of all available data. First, cases of faults caused by pollution were analyzed to establish if these were still concentrated mainly in the São Pedro Mountains. This would confirm whether the primary problem was loss of coating effectiveness or if there was also growing pollution dispersion, i.e. other areas of the line were beginning to suffer from this problem as well.

Table 1 lists failures since 2010, showing all towers affected as well as their type and the phases involved. One important clue coming from this data was that all flashover outages were occurring either at dawn or during the night. This reinforced the role played by humidity. Moreover, the fact that outages were often bi-phasic to ground suggested that both phases had similar characteristics. Finally, tower silhouettes were compared to confirm if faults were concentrated on the same type of insulator configuration (see Figs. 6 and 7).

Insulation on the Xingó-Angelim II Line was designed with 8320 mm creepage distance (i.e. 15.12 mm/kV) along the entire route – a value corresponding to light pollution according to IEC 60815. In order to confirm if problems were occurring only in hilly areas, a chart was plotted showing altitude of each tower in the line (see Fig. 80). Indeed, most towers affected were in the section passing the São Pedro Mountains and at much higher elevation than elsewhere on the line. This would make them more susceptible to conditions of fog and mist.

To better understand the role of natural cleaning, data was also collected on local rainfall patterns over recent years, using the town of Bom Conselho, located in the middle of the hilly area, as reference (Fig. 9).

First Mitigation Program

Results of the study highlighted the need to concentrate mitigation efforts on towers near the São Pedro Mountains since this area was the focus of insulation failures due to natural pollution. Possible mitigation alternatives were compared in light of several factors:

• Numbers of strings involved;

• Cost of implementation;

• Experience at other utilities;

• Penalties applied by national regulatory authority;

• Safety of linemen and asset;

• Nature of solution.

Considering the positive service experience with composite insulators applied on transmission lines in the same region as well as TAESA’s own experience with them, a recommendation was made to replace all 618 glass insulator strings between Towers #284 and #397 with an extra high pollution design of silicone insulator. This recommendation included towers with suspension as well as strain insulator assemblies. The composite insulators selected had almost 15,000 mm creepage distance, i.e. about 80% higher than the coated glass strings they would replace. They also offered superior hydrophobicity and other desired electrical properties (shown at Table 2). Application of these polymeric insulators increased specific creepage distance from 15.12 mm/kV to 27.3 mm/kV, enhancing line insulation to face pollution levels classified between heavy and very heavy. After their acquisition, an intense coordinated effort allowed replacement of all old strings in only three days of work with the line de-energized (Fig. 10).

Recurrence of Outages

In 2016, after only about a year with the new polymeric strings, the line faced another increase in outage rate. While the outages had the same basic characteristics as past problems due to natural pollution, this time they were focused on towers located outside the São Pedro Mountains. Maintenance crews conducted corona camera inspections on some of these line sections to check what could be happening (see Figs. 11 and 12) and results showed that corona activity on glass insulator surfaces had increased dramatically. This confirmed suspicion of an unexpected high pollution phenomenon.

The main issue then became to understand why these problems had not occurred before since the basic geographic conditions had not changed. The only possible explanation behind the sudden spike in outages could be a change in local rainfall. O&M Engineers therefore analyzed precipitation patterns from 2015 and 2016, relying on data from Pernambuco since data from Sergipe and Alagoas States was not readily available. The assumption was that level of rain activity in all these regions behaved more or less the same, based on past experience.

Looking at this data showed a notable decline in rainfall in 2016 compared with the previous year, except for Terezinha Station. There was also an extension of the dry season at most weather stations. This evidence could lead to future action to prevent new such outages by replacing the toughened glass insulators remaining in service on this line with the same high pollution polymeric type used near the São Pedro Mountains.

Monitoring Composite Insulators

Application of this new insulator technology has brought with it the need for different inspection programs and techniques to prevent occasional failures and new outages. The corona camera already used is expected to help maintenance crews analyze evolution of pollution accumulation on polymeric surfaces over the years. However, to check for incipient problems leading to risk of brittle fracture, periodic close-up visual inspections will be required in combination with techniques such as E-field measurement and X-raying samples removed from the line. As of the end of 2017, the O&M Engineering Team had begun to establish a regular inspection plan for these insulators, using all these techniques, as well as revised inspection protocols to be undertaken by maintenance crews.

Conclusions

The 500 kV Xingó-Angelim II Line passes through an area of heavy natural pollution not sufficiently considered during project design. A combination of this and concentrated high humidity has resulted in this asset experiencing high outage levels over the years. The São Pedro Mountain Range was studied first since all outages were concentrated there. The solution first applied proved successful and the number of outages decreased, even before eventual replacement of toughened glass strings with a composite polymeric type. The subsequent spread of outages having the same characteristics as at other parts of the line suggested that the combination of humidity and pollution was again likely affecting insulators, but now at different locations. The logical conclusion was that these faults had not occurred before since the hills were the ‘weakest’ part of the line under humidity conditions. Once problems in this section had been resolved, other weaknesses began to show up.

The O&M Engineering Department was able to find support for this theory by analyzing data to confirm a decrease in precipitation during the rainy season in the year immediately after the first insulator replacement. This lack of rain brought with it increased pollution accumulation on glass insulator surfaces, which then triggered flashovers under conditions of high humidity. To resolve this, the same solution applied in the first case is considered, i.e. replacing existing glass insulator strings with polymeric types. Moreover, data from corona camera images has proven valuable in determining criticality of those strings needing to be replaced as soon as possible. Finally, different line inspection techniques will have to be implemented for the new polymeric insulators and TAESA is equipping and training its teams for this challenge.

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

Romania

GCC Electrical Testing Laboratory

Kingdom of Saudi Arabia

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[1] HAMPTON, BFi, 1964. Flashover mechanism of polluted insulation. Proceedings of the Institution of Electrical Engineers. IET Digital Library. p. 985-990. ISSN 2053-7891.
[2] DE MELO, Josemir C, 1999. O fenômeno El Niño e as secas no Nordeste do Brasil. Raízes, ano XVIII, nº 20, p. 13-42.
[3] DA SILVA, VICENTE DE P. R.S. et al, 2012. Estudo da variabilidade anual e intra anual da precipitação da região Nordeste do Brasil. Revista Brasileira de Meteorologia. Vol. 27(nº 2). p. 163-172.
[4] DE MELLO, Darcy R., et al. Avaliação do Grau de poluição em instalações de transmissão, subestações e distribuição. I Citenel. Brasília, 2002.
[5] TAESA, 2015. “Estudo sobre a falta provocada por flashover nos isoladores das fases B e C na torre 284 da LT Xingó – Angelim II.” Rio de Janeiro:TAESA. NTE.RT.0052.00.
[6] QUINTAS & QUINTAS, 2002. “Sistema de Transmissão Xingó – Angelim 2 – Projeto Básico IN-LT500-PB-0100,” Rio de Janeiro:Quintas&Quintas. IN-LT500-PB-0100.
[7] IEC, 2008. IEC T. S. 60815-1:2008. Selection and dimensioning ofhigh-voltage insulators intended for use in pollutedconditions-Part, 1. IEC.
[8] AGÊNCIA PERNAMBUCANA DE ÁGUAS E CLIMA, 2015. “Boletim Pluviométrico Diário – 07/06/2015,” Recife: APAC. [Viewed 6 julho 2015]. Available from: http://www.apac.pe.gov.br/arquivos_portal/boletinspluviometricos/Boletim_Pluviometrico_07.06.pdf.
[9] BARROS, Alexandre Hugo Cezar, et al., 2012. Climatologia do estado de Alagoas. Recife: Embrapa Solos-Boletim de Pesquisa e Desenvolvimento (INFOTECA-E).

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Revision of IEC 61109 on Composite Suspension & Tension Insulators by Bastian Robben

Revision of IEC 61109 will impact aspects of both production and testing of composite suspension and tension insulators.

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Stringent international regulations are also pushing utilities to rely on testing as one of the most effective means to demonstrate that they are working with due diligence whenever specifying such equipment. This requirement becomes the more important if one considers the growing numbers of substations and electrical installations located near population centers as well as the accompanying push to reduce substation ‘footprint’.

Both trends represent increased risk factors in terms of danger to public safety as well as economic consequences of collateral damage should there be catastrophic failure. It is therefore increasingly important to look for possible upgrades in technology while also decreasing failures at the early stages of service life. The latter can only be achieved through more detailed installation practices in which all critical functions are well defined and where greater attention is paid to the skills required of the workers involved.

According to ISO/IEC Guide 51 safety is ‘freedom from unacceptable risk’. This can be achieved by reducing risk to some tolerable level that takes into account that there will always be some residual risk, i.e. the risk that remains after all possible protective measures have been undertaken. This risk is then determined by arriving at some optimal balance between the ideal of absolute safety and the demands met by the product, which includes benefits to the user, suitability for purpose and cost effectiveness. Safety criteria must be considered first in order to be able to specify the required safety level and to perform any related risk assessment. One way to do this is to combine all the technical as well as non-technical, e.g. social and economic, parameters that play a role in evaluating failure probability and its consequences. For example, to reduce residual risk and also to lower the cost of consequences, explosion-free bushings are increasingly being specified.

Failures of bushings are responsible for a significant proportion of all transformer failures and can be violent. Although often regarded as only accessories, bushings are in fact the cause of roughly 80% of failures and fires involving transformers filled with insulating mineral oil – even if fire actually occurs in less than 15% of all transformer failures.

Failures of bushings can result in the porcelain housing shattering into shards and other fragments that are projected at high velocities over a wide area. Moreover, oil that is sprayed out through the cracked unit can be ignited by the arc associated with the fault. In extreme cases, fireballs higher than the transformer itself have been observed following explosive failure of a bushing. Physical protection against explosions and fires involving HV bushings in service are difficult or even impossible to put in place due to the size and location of the equipment. Whenever a particular type of bushing is regarded as being at unacceptably high risk of such failure, access to the site should be limited, during which time design changes to improve safety can be discussed with the manufacturer. Because of the considerations discussed above, explosion-free designs of HV bushings – sometimes still seen as a comparatively new technology – are increasingly used to obtain lower risk solutions in applications where substations are located in urban areas with buildings in the vicinity. While testing explosive behavior may not yet be mandatory, it is increasingly being conducted to enhance reliability and reduce risk – irrespective of location of a power installation.

Procedures for Internal Arc Testing

Testing and certification are important tools to assure the safety and reliability of electrical networks. Among the HV components most often submitted to testing for safety reasons are bushings, cable terminations and arresters. The main difference when testing these components lies in the applicable situation in respect to the norms. While IEC and IEEE standards already exist for arresters, there are no international standards available for HV bushings and cable terminations. Rather, technical specifications for these have been prepared by major national utilities while European standards are also available.

The HD standard, for example, prescribes triggering the internal arc in a termination by drilling a hole in the main insulation. A 1.5 mm² copper wire then connects to the screen/metal sheath or a piece of metal is connected to the shield/sheath in order to simulate failure. Later, a short circuit current is applied, whose values (kA and seconds) are chosen according to the maximum short circuit current of the circuit where the HV termination is to be installed. In spite of the fact that the scope of this standard is limited to cables and accessories up to 170 kV, the same test modalities are also now being used for higher ratings of terminations as well as for bushings. Based on experience from such tests, an internal arc test on bushings is demanding both for the power laboratory and the manufacturer since:

• test set-up and auxiliary electrical facilities such as power source connections, etc. need to be expressly installed and then dismantled after the test;

• demanding protection measures have to be put in place to avoid environmental problems;

• ejected parts from violent shattering can damage the test chamber and even surroundings;

• smoke and noise are harmful to test staff and the environment, which, taken together with the high test ratings, may require overnight tests.

These challenges will only become greater in the future if one considers the increasing market demand for higher values of short circuit current.

Summary & Conclusions

Worldwide demand for power networks will only increase, pushing utilities to install growing populations of HV bushings and other equipment vulnerable to catastrophic failure. At the same time, attention to safety and the environment is also growing. Proper selection of the ratings and characteristics of these components together with high quality levels will be key to reducing the probability of failures even though risk of such events can never be disregarded. Therefore, laboratory tests to simulate internal fault remain a useful tool to help select those products that have safe performance during failure and reduce risk of violent explosion or fire on the network. Requirements for safety of substation equipment will only become more stringent. As such, it will also become important to harmonize and standardize testing requests coming from utilities across the globe.

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Similarly, the substation insulation selection process going forward will have to comply with the latest chemical regulations as well as maintain a preference for green, non-hazardous and sustainable materials. Finally, the IEC has agreed to support the UN’s sustainable development goals when issuing standards. In parallel, more eco-friendly materials are being developed along with re-use and recycling methods that must adhere to the latest safety, health and environment (SHE) regulations.

This edited contribution to INMR by expert consultant Dr. Jens Seifert, prepared on behalf of Saver in Italy, explains how all these factors will impact the latest generation of composite hollow core insulators and GIS bushings.

Hivolt Power System

China

PFISTERER

Germany

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Composite Hollow Insulators

As stated in IEC 61462, hollow core composite insulators (HCIs) are among the key components of HV apparatus used at substations. They serve as housings that guarantee the required mechanical (i.e. bending, pressure, tightness) as well as electrical properties and protect against environmental stresses.

These are produced for AC and DC applications with special design approaches in each case and their range is specified within IEC 60815 (recently expanded to also offer insight regarding DC voltage stress), which provides guidance for best design in respect to polluted conditions.

So far, there are no specific characteristic or dimensional standards for HCIs, and it seems unlikely these will be realized in the future. The reason for this includes specific customer design requirements as well as historical product portfolios and specifications on the part of users, i.e. OEMs and TSOs. The resulting greater variety in designs needs to be handled through smart production and a logistics system that guarantees acceptable lead times.

A. Materials
Silicone rubber has been the state-of-the-art material used in HCI housings for decades. Nonetheless, its development has continued to progress with regards to performance, e.g., tracking and erosion, hydrophobicity and mechanical properties. Regarding SHE, for example, a key step has been taken with introduction of platinum (Pt) catalyzed curing systems for LSR and HTV processing technologies (i.e. injection molding and extrusion).

Pt catalyzed addition curing systems do not emit hazardous volatile substances, e.g. from former standard peroxidic curing agents based on C6 or C1. The latter will eventually disappear since ECHA/SVHC regulations will ban these step-by-step. The latest example is the SVHC candidate proposal of dicumyl peroxide (DCP) C1 agent. The different stages in the SVHC process include ‘information for users’, ‘proof of concentration below limit value (e.g. 0.1 % by weight)’, ‘approval of application’, and finally ‘complete ban’.

Regarding epoxy resin impregnation, a process is already in place for anhydrate hardeners where two chemicals have now been replaced. In the ECR glass fiber roving production industry, there is greater consolidation since SHE rules increasingly request formal approvals from local agencies, resulting in increased effort and material costs. For HCI manufacturers, this means additional burden to renew the qualification process with related time and added costs once required changes in raw material are announced by suppliers.

This is not ideal since it hinders quality suppliers that comply with European Union standards while unintentionally benefitting suppliers in countries that do not comply yet still supply the EU market. Given the recent changes in how OEMs and TSOs qualify suppliers, this situation may end of being considered during the supply chain process.

B. Technology Trends
Regarding processing technologies there are clear trends: Injection molding using LSR and HTV materials will account for the bulk of total production with mold-based processes resulting in equivalent performance for both LSR and HTV silicone rubbers. Extrusion technologies (using mainly HTV rubber) and 3D printing (with both LSR and HTV) will be applied to manufacture insulators of very large size or having special conical/barrel shapes as well as for direct application of a silicone housing to dry-type cable terminations.

C. Alternative Gases
Although SF₆ is a highly efficient insulation and switching medium, the latest REACH decisions will see the gas banned by 2036 in two steps: 145 kV by 2032; >145 kV by 2036). The search for alternative gases started in the 1990s resulting in recognition that replacement media also have high greenhouse potential. Still, these are lower than SF6 especially if diluted with carrier media such as N₂, CO₂ or O₂.

This issue is important for insulation applications such as gas-insulated bushings, and instrument transformers as well as for switching applications. Gas mixtures based on fluoronitrile (FN) or fluoroketone (FK) are available and proven by respective testing with peak breakdown strength of 55…70 kV/cm (vs. 80 kV/cm for pure SF₆). These alternative gases require special machines for filling/re-filling that differ from those used for SF6. As an alternative, use of dry ‘technical’ air is being applied by some OEMs. One disadvantage is relatively low breakdown strength (30 kV/cm peak), meaning pressure must be increased while insulation distances/diameters will typically increase by at least one class.

The switching function in related circuit breakers is handled by vacuum breaker tubes, a concept that has a fully ‘green’ and economical footprint regarding insulation and vacuum breakers. For HCIs used in ‘dry air/clean air’ applications, special measures must be taken during design to mitigate CO₂ and O₂ diffusion processes.

D. Life Cycle Assessment (LCA)
Over the past years, LCAs for HCIs have been performed either as part of EU funded projects or supported by large OEMs and TSOs. Results have shown consensus, i.e.:
• Total service life is equivalent to that of porcelain;
• Recycling and re-use characteristics are similar to those offered by ceramic insulators;
• CO2 footprint is better than for conventional insulators while emission of fine dust is much lower for polymeric materials;
• Performance is better compared to porcelain, especially for HVDC applications and/or under polluted service conditions;
• Aspects such as hardening substations against threat of terrorism favor their use at substations, especially in the United States. A relevant IEEE Task Force was established in 2018;
• Superior TCO compared to conventional ceramic insulators.

GIS Bushings

Bushings having HCI housings and SF6 as a highly efficient gas or with N₂/SF₆ gas mixtures have been applied at gas-insulated substations since 1967 (see Fig. 1). Mixtures with a ratio of e.g. 80/20%, show almost the same insulation performance as pure SF₆.

In terms of switching performance, however, there is a big difference given that SF₆ is difficult to replace 1:1 in such applications and technical re-design may be required. Experience with SF₆ insulated systems has been uniformly good with no reports of leakage. Still, SF₆ will be banned across the board, even though the HV apparatus industry has been a relatively small user and has generally handled the gas in a safe, controlled manner.

With new regulations in Europe (e.g. REACH/SVHC) as well as in countries such as the U.K., India and Australia, use of SF6 shall be limited and sunrise dates are already defined for different system voltage classes (≤145 kV and >145 kV) to phase out its application in HV apparatus by 2032 and 2036 respectively.

In the case of GIS bushings, there are least two solutions: application of alternative gases or use of dry technical air with higher maximum service pressure (MSP) – typically in the range 10…14 bar gauge to compensate for lower initial electrical strength. Despite the greater pressure, an increase of at least one diameter class will normally be required.

For alternative gases there is also the option to manage the lower electrical strength by increasing pressure or diameter. Care must then be taken with regards to compatibility of materials (e.g. metal, polymeric material, sealings) insofar as the decomposition products of FN and FK gas mixtures. Several compatibility investigations have already been carried out and indicate that special care must be taken to protect both the flange assembly glue and sealing rings. Managing FRP tube compatibility can be achieved using the same measures as against SF6 decomposition by-products.

GIS is a space saving concept as demonstrated by the 420 kV hybrid substation at Simbach am Inn in Germany (see Fig. 2). There, the technology chosen aimed to use best practice in reducing the station’s footprint combined with highest system reliability as well as strong public acceptance. The last factor has become increasingly important for approval of new HV infrastructure. For example, the space and land area requirement for this project was only 10 to 20% that of a conventional air-insulated switching field with conventional live tank or dead tank circuit breakers, post insulators, ITs, surge arresters and related disconnectors.

Compact substations offer significant reduction in visual impact, and the life of such hybrid substations is the same or longer than for conventional substations since they are unaffected by environmental stresses. LCA and TCO calculations both reveal the benefits that help convince TSOs and public stakeholders to apply this technology in the future.

Composite Station Posts

Composite solid core station post insulators according to IEC 62231 offer advantages up to 245 kV (e.g. pollution resistance, resilience, seismic performance, less weight). Equivalent insulators for the North American market are standardized in ANSI C29.18. IEC and ANSI versions differ mainly in routine, sample and type test requirements. Also, ANSI has a higher level of dimensional specifications in terms of TR classes, derived from the long-established porcelain standard, ANSI C29.9.

For voltage classes above 245 kV, composite hollow station posts (CHSP) are preferred. These are typically governed by IEC 62772, especially since there are virtually no limits in single unit length and diameter (see Fig. 3). Solid media (e.g. foam) filled CHSPs are applied in the medium segment while the upper end ≥765 kV is typically filled with insulating gas. IEC 62722 was recently revised, in parallel to IEC 61462, to reflect the latest internal and external interface testing requirements.

Applications include:
• Bus bar supports (substations);
• Disconnector switches;
• HVDC converters;
• HVDC substations in high-polluted areas;
• HVDC substations near to marine environment (offshore energy facilities);
• HVDC and HVAC in seismic critical areas;
• UHV applications (replacing porcelain due to weight and superior pollution performance);
• FACTS / platforms (UPFC, SVC, capacitive and reactive compensators);
• Coil supports;
• Optical CT/VT supports;
• Optical fiber bushings (station post type).

CHSPs having more than 10m length and >580mm internal tube diameter have already been developed for large HVDC links where the coil acts as a reactor at the converter station. Multiple CHSPs, according to IEC 62772, are filled with gas under pressure, which is monitored and controlled. The monitoring system is the weak link for potential leakage although HCIs that are properly designed and tested for this application can be considered as offering a ‘lifetime seal’.

The concept of lifetime seal considers the leakage rate obtained during the routine tightness test. Based on maximum leakage rate measured, allows calculating total loss of pressure over 40 years application/service life. For example, quality units show loss of pressure of less than 10% meaning that, if gauge pressure is set to 0.5 bar, the loss over 40 years is less than 50 mbar. This ensures that there will still be sufficient overpressure to protect the hollow volume inside from ingress of humid air and moisture.

The main load on composite post insulators in coil applications is compression and CHSPs are preferred for this application because of their superior single-unit mechanical design along with excellent performance of hydrophobic silicone under pollution and DC voltage stress. In disconnector switch applications, the main load is bending during operation and due to additional loads. For proper function of the contact systems of these switches, stiffness must be high to secure low deflection under load. This can be achieved given the high moments of inertia of large diameter CHSPs.

Other drivers favoring application of solid and hollow core composite station posts are seismic resistance, high mechanical impact strength and failure modes that do not exhibit bursting, explosion or emission of fragments.

Hollow post insulators are also the base technology underlying optical diagnostic/monitoring equipment and net level of optical instrument transformers, usually placed on the head or inside a hollow post insulator. The hollow composite station post insulator also acts as mechanical support for diagnostic/measuring devices with connected conductor and serves as insulating bushing for the optical fiber fed through the hollow core. Typically, the internal hollow volume in these applications is filled by an insulating foam or jelly, although gas is used in rare cases.

Cable Terminations

Cable terminations for HVAC and HVDC are now increasingly important, especially in the latter case for marine and land cable transmission projects at 320 and 525 kV system voltage. Presently, offshore wind farms and photovoltaic generation are connected using 320 kV cable system technology in the North Sea and Baltic Sea (i.e. Germany, U.K., Poland and Scandinavia) as well as in the Mediterranean (e.g. Tyrrhenian Link, Montenegro-Italy, Attica-Crete and Adriatic Link).

With growing power generation capacity, however, 525 kV transmission technology has been selected for future such connections as well as for long-distance transmission technology (marine and land cables). Examples include the Süd Link and Süd Ost Link as well as future 2 GW transmission projects across Germany. All generation for these applications was selected for being environmentally friendly “green” resources and replacing fossil and nuclear fuel used for decades. This change has been called Energiewende in Germany and is part of the political debate since 2015. Similar projects are now planned in the U.K., Scandinavia, Poland and Benelux.

Technical expectations of these relatively new products including DC land cables and related joint and termination accessories is high, especially with regards to reliability and longevity. Nonetheless, experience is still limited for 525 kV such systems. The cable termination, for example, must be equipped with composite hollow insulators of large dimension in terms of diameter and length, e.g. the SOL cable termination for high pollution class has a length of 6500 mm. Terminations are filled with gas (see Fig. 5).

The reasons for choosing HCIs include:
• High-pollution resistance of their silicone housings;
• Oil-free designs offering no risk of explosion and/or oil contamination in case of failure such as from short circuit. Figs 4 & 5 show dry type and gas-insulated oil-free terminations. Filling can also employ alternative gases;
• High mechanical impact strength along with a non-critical failure mode (i.e. no burst or emission of sharp elements);
• Flexible length and diameter in design of the stress cone/field grading element (see Fig. 6).

Trends, Challenges & Future Developments

A. Composite Hollow Insulators
• Modern composite hollow core insulators (HCIs) are manufactured using environmentally friendly processes with a sustainable and transparent supply chain and low CO2 footprint.
• Addition vulcanizing (platinum catalyzed) silicone systems are replacing peroxide curing systems. Addition curing systems do not emit hazardous volatile compounds and are fully in compliance with REACH/SVHC regulations. This also applies for other polymeric materials employed.
• Life-cycle assessment (LCA), i.e. cradle to grave considerations, is required and must demonstrate all related efforts as well as net advantages and disadvantages – not only in terms of cost but also environmental impact.
• Alternative gases and their decomposition products must be considered and HCIs are equipped accordingly.
• With increasing demand for EHV, UHV and HVDC solutions, future composite insulators designs need to be realized in extreme dimensions, e.g. lengths over 12m and inner diameters larger than 1000mm. Suitable manufacturing processes will need to be developed or enlarged.
• Alternative gases show lower electrical strength than SF6 and this will mean higher internal pressures for insulation. HCI designs for such applications will need to accommodate higher maximum service pressures (MSP), according to IEC 61462, resulting in higher SIP as well as higher routine testing pressure (i.e. 2 x MSP). Designs will have to be upgraded to allow more robust, higher-strength insulators.
• The total cost of ownership (TCO) approach considers all parameters, not only the cost (price) of materials. OEMs/TSOs are increasingly adopting such a philosophy, which contains LCA assessment and a range of other input parameters resulting from SHE, handling and maintenance over the full service/operating life of HV apparatus.
• Aspects such as ‘hardening’ substations against terror attack are key promoters for application of HCIs at substations.

B. GIS Bushings
• Composite insulators will increasingly replace porcelain due to reasons on better pollution performance and safety.
• Alternative gases/dry air will replace SF6 due to REACH regulations.
• Achieving compact design given the lower electrical strength of alternative gases will represent a challenge.
• Electrical field grading/field control technology will be an effective design tool to reduce diameters and allow more compact bushing designs.

C. Composite Station Posts
• Composite insulators will replace porcelain due to superior pollution performance and seismic resistance.
• Light weight, high-strength, and design as well as manufacturing flexibility are enabling application of CHSPs, with gas or foam filling media, for voltage classes exceeding 550 kV EHV AC, 800 kV HVDC and 1200 kV UHV AC.
• The ‘lifetime seal’ concept for CHSPs will help avoid need for expensive and vulnerable gas monitoring systems for gas-filled units.
• Over the next 20 years, composite station post insulators are expected to outperform and replace conventional ceramic insulators in all applications due to their economic, ecological and technical advantages. This also considers their evaluation according to the TCO model which includes initial product costs, supply chain, environmental requirements, maintenance, lifetime and risk assumptions.

D. Cable Terminations
Modern cable terminations are oil-free (for safety and environmental constraints) and use either dry-type or gas-filled technology. Dry types can be realized with different technologies, based on the intellectual property of the manufacturer.

• Dry-types are replacing oil-filled, with gas filled insulation for higher voltage classes.
• Composite insulators will increasingly replace porcelain types due to SHE constraints.
• Plug-in technology for easier handling and installation is the trend since most failures are caused by improper connection and installation.
• Condenser style bushings (resin-impregnated condenser core – RIS/RIP style) are alternatives to gas-filled solutions and fall in the ‘dry type’ category.

E. Optical Instrument Transformers (ITs)
Conventional instrument transformers (ITs) use SF6 gas or oil as insulating media to embed and isolate the transformer windings. This design principle has been proven for decades and is highly reliable. Over the past 20 years, however, a new IT principle has emerged based on optical physical effects.

Current transformers (CTs) have reached a high degree of maturity and acceptance by TSOs (see Fig. 7). The active optical CT head is placed on top of a hollow post insulator with optical fibers connected to it. The hollow post insulator acts as an optical fiber bushing accommodating a bundle of fibers internally embedded with a gas, liquid or polymeric insulation medium.

Similar optical principles are also used at HVDC converter stations and for monitoring/diagnostic purposes at substations and on overhead transmission lines (e.g. for temperature measurement, fault location, etc.). Insulation between high voltage (where the sensors are placed) and ground is realized by ‘signal columns’ which are slim HCI elements, typically as tension or suspension units.

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References
[1] IEC 61462:2023, Composite Hollow Insulators – Pressurized and unpressurized insulators for use in electrical equipment with rated voltage greater than 1000V – Definitions, test methods, acceptance criteria and design recommendations.
[2] https://echa.europa.eu/
[3] CIGRE Technical Brochure No. 849, Electric performance of new non-SF₆ gases and gas mixtures for gas insulated systems, October 2021.
[4] C4-FN Mixtures for High-Voltage Equipment, Handbook, GE Vernova, Hitachi Energy, May 2023.
[5] C.H. Olsen et. al, Diffusion of CO2 through Polymer Membranes, Environmental Impact V, www.witpress.com, ISSN 1743-3541 (on-line), WIT Transactions on Ecology and the Environment, Vol. 245, © 2020 WIT Press.
[6] Y. Tu et al., Feasibility of C3F7CN/CO2 gas mixtures in high-voltage, High Volt., 2020, Vol. 5 Issue 4, pp. 377-386, this is an open access article published by the IET and CEPRI under the Creative Commons Attribution: Non-commercial License, (http://creativecommons.org/licenses/by-nc-nd/3.0/)
[7] Y. Li, Study on the thermal decomposition character-istics of C4F7N–CO2 mixture as ecofriendly gas-insulating medium, High Volt., 2020, Vol. 5 Issue 1, pp. 46-52 This is an open access article published by the IET and CEPRI under the Creative Commons Attribution: Non-commercial License, (http://creativecommons.org/licenses/by-nc/3.0/)
[8] IEC 62231-1:2015. Composite station post insulators for substations with AC voltages greater than 1 000 V up to 245 kV – Part 1: Dimensional, mechanical and electrical characteristics.
[9] ANSI C29.19:2020. Composite Station Post Insulators.
[10] IEC 62772:2023. Composite hollow core station post insulators for substations with a.c. voltage greater than 1000 V and d.c. voltage greater than 1500 V – Definitions, test methods and acceptance criteria
[11] switchgearcontent.com
[12] www.powerandcable.com
[13] Prysmian Group, Technical Brochure: Click Fit® – High Voltage Accessories for Extruded Cables, Milano, Italy, 2023.
[14] J.M. Seifert, H. Ye; New Concepts in Voltage Grading, INMR 2015, MC-04, Munich, Oct. 15-17th, 2015.
[15] Patent Publication No. 20110017488; FIELD-CONTROLLED COMPOSITE INSULATOR AND METHOD FOR PRODUCING THE COMPOSITE INSULATOR, Lapp Insulators GmbH, 27.01.2011.
[16] Trench Group Ltd.; REGENERA® – Optical Current Transformers, Technical Product Brochure, www.trench-group.com, 2024.
[17] www.hspkoeln.de/en/products

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