This scenic region of Portugal is dotted with magnificent seascapes, picturesque towns, and historic castles.

The 3-day conference at the 2027 INMR WORLD CONGRESS will feature 150 technical presentations spread across 8 Sessions. These Sessions will cover all areas of electrical insulation and surge protection.

SESSION 1: PLENARY SESSION (in ENGLISH)
Selected technical lectures offering an overview of key topics on electrical insulation and surge protection. These topics will then be explored intensively during Sessions 3 to 8.

SESSION 2: PLENARY SESSION (in PORTUGUESE & SPANISH)
Esta sessão irá rever os elementos-chave de todos os tópicos em um único dia.
En esta sesión se revisarán los elementos clave de todos los temas tratados en un solo día.

SESSION 3: MATERIALS (in English)
Insulation materials and technologies optimized for today’s manufacturing and service performance requirements.

SESSION 4: MANUFACTURING EQUIPMENT & TECHNOLOGIES (in English)
Developments in injection molding and other production equipment to meet evolving industry needs for quality, productivity, and energy efficiency.

SESSION 5: LABORATORY TESTING (in English)
Laboratory testing and requirements linked to updated standards and changing customer needs.

SESSION 6: POLLUTION & DESIGN (in English)
Assessing service environments and designing for optimal performance under pollution.

SESSION 7: APPLICATION & SERVICE EXPERIENCE (in English)
Insulator designs and service experience across different AC and DC applications.

SESSION 8: CONDITION MONITORING & MAINTENANCE (in English)
Technologies and equipment for condition monitoring and maintaining power system components and equipment.

As at past such events, a large PRODUCT & TECHNOLOGY EXHIBITION will run in parallel to the 3-day Conference and feature leading component and equipment suppliers from across the globe.

MEET, LEARN, NETWORK

For more information, visit: www.inmrworldcongress.com

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How do you compare CIGRE and the INMR WORLD CONGRESS?

Below, Google AI answers this question:

“Comparing CIGRE (International Council on Large Electric Systems) to the INMR WORLD CONGRESS involves looking at the difference between a broad, foundational research organization and a focused, application-driven technical forum. While both are premier events for power transmission and distribution (T&D) professionals, they differ significantly in scope, focus, and structure.

CIGRE (Sessions/Symposiums) is a global, research-oriented organization covering the entire spectrum of power systems.

INMR World Congress is a specialized, industry-driven event focused heavily on outdoor insulation, surge protection, and cable accessories.

Key Comparisons

Scope and Focus:

• CIGRE: Offers an end-to-end view of power systems, covering everything from low-voltage distribution to high-voltage transmission, system planning, and operation. Its focus is deeply technical, driven by international working groups.

• INMR World Congress: Focuses on the “T&D infrastructure” components, specifically advancements in insulators (composite, glass, porcelain), surge arresters, bushings, and cable accessories. It acts as a bridge between research and practical application.

Target Audience:

• CIGRE: Attracts researchers, engineers, academics, and strategic planners involved in long-term power system development.

• INMR World Congress: Attracts utilities, asset managers, manufacturers, and testing laboratories concerned with the reliability, maintenance, and specification of components.

Technical Approach:

• CIGRE: Focuses on developing technical brochures, working group recommendations, and long-term studies.

• INMR World Congress: Focuses on 3-day conferences featuring ~150+ technical lectures, heavily featuring case studies, practical experience, and “know-how” for environmental challenges like pollution and lightning.

Exhibition and Networking:

• CIGRE: Has a massive exhibition featuring a wide range of technology providers from transformers to digital solutions.

• INMR World Congress: Includes a product & technology exhibition focused specifically on material suppliers, mold manufacturers, and testing equipment for insulation and accessories.

Industry Role:

• CIGRE: Often considered the “authority” for standards-setting recommendations (often in conjunction with IEC) and deep technical expertise.

• INMR World Congress: Provides a unique platform for knowledge sharing and networking among specialists, often with practical, immediate-use application to improve grid performance.”

Key Takeaway

If you need to understand the big picture of future power systems, CIGRE is the premier venue. If you need to know how to select, test, or maintain insulators, surge arresters, and cables to increase grid reliability, the INMR World Congress is the more direct choice.

Comparing CIGRE and the INMR World Congress reveals two distinct styles of technical exchange within the power industry. While both share a common goal of grid reliability, they differ significantly in their technical scope and the nature of their sessions.

Event Style & Discussion:

• Typical CIGRE sessions are highly structured with formal presentations and limited time for questions. However, specific events like the CIGRE Colloquium may offer more free-form discussions.

• The INMR World Congress is designed as a “skills-enrichment” event, emphasizing technical lectures (often 150+) and a parallel product exhibition where attendees can discuss specific component needs directly with suppliers.

Frequency and Scale:

• CIGRE holds its massive Paris Session biennially (e.g., 2024, 2026), often drawing thousands of participants worldwide. It also hosts smaller regional symposia, like the one in Montreal in 2025.

• The INMR World Congress typically occurs every two years in diverse global locations, such as Panama City (2025) and the Algarve, Portugal (2027).

Which One to Choose?

Interestingly, there is significant overlap between the two; for example, the current President of CIGRE, Dr. Konstantin O. Papailiou, was a keynote speaker at INMR and received its prestigious Claude de Tourreil Memorial Award in 2025.”

The post AI Compares CIGRE and INMR WORLD CONGRESS appeared first on .

This edited contribution to INMR by Alfonso Ambrosone and Christopher O’Donnell at GE Vernova highlights the critical role of advanced online monitoring systems, enabling real-time assessment of bushing health, facilitating early detection of emerging faults and supporting condition-based maintenance (CBM) strategies. Online bushing monitoring systems provide continuous, real-time diagnostics that significantly improve visibility into a transformer’s internal state. By utilizing sensors that track essential parameters such as capacitance and Power Factor (tan delta), these systems offer early detection of insulation degradation, moisture ingress, and thermal anomalies issues that typically evolve gradually and evade detection through periodic assessments. This proactive monitoring approach results in enhanced reliability, reduced unplanned outages, and more accurate performance benchmarking across the transformer fleet.

Three case studies are also discussed which show how trending of online data helped trigger alarms and then to actionable offline test data for pro-active bushing replacement. Such enhanced visibility enables better integration of operational information, empowering Operations Managers to make more informed decisions and significantly reduce risk of major failures.

Hivolt Power System

China

PFISTERER

Germany

See more suppliers of Bushings

Key Failure Mechanisms of Condenser Bushings

Oil-Impregnated Paper (OIP) condenser-type bushings are widely used in high-voltage transformers due to their excellent dielectric properties and long service record. They are composed of a central conductor wound with alternating layers of paper insulation and conductive foil, forming condenser or capacitive layers. These layers are housed within a protective weather-resistant casing, typically porcelain, and impregnated with insulating oil to enhance dielectric strength. Within the bushing, two primary capacitances exist, designated as C1 and C2 (see Fig. 1). C1 represents the total capacitance between the central conductor and the test tap, which is connected to the outermost capacitive layer and serves as the primary measurement point during diagnostic testing. C2 denotes the capacitance from the test tap to ground and is not part of the active circuit during normal bushing operation.

The capacitive layers are engineered to ensure uniform voltage distribution across the bushing by functioning as a voltage divider. Still, despite their robustness, OIP bushings are susceptible to certain failure modes (typically associated with moisture ingress, oil degradation and seal failure), which can compromise reliability and lead to catastrophic equipment failure if undetected:

• Moisture Ingress:
Degraded seals or malfunctioning breathers can permit ambient moisture to enter the bushing, leading to increased dielectric losses and a rise in the dissipation factor (tan delta). Moisture ingress is one of the primary contributors to accelerated ageing in OIP bushings since it significantly diminishes the insulating properties of the oil-impregnated paper system.

• Oil Degradation:
Over time, thermal ageing and oxidative processes can degrade the insulating oil, resulting in formation of acids and sludge. These by-products reduce dielectric strength of the oil and can create conductive paths, increasing risk of electrical breakdown.

• Partial Discharge (PD):
Presence of moisture, voids, or contaminants within the insulation system can initiate partial discharge activity. PD is characterized by localized electrical discharges that do not immediately bridge the insulation but gradually erode it, potentially leading to complete dielectric failure if left unaddressed.

• Thermal Runaway:
Elevated dielectric losses (often triggered by moisture ingress) can lead to localized heating within the bushing. This internal heat accelerates insulation degradation in a self-reinforcing cycle that can ultimately result in thermal runaway and catastrophic failure.

• Mechanical Cracking:
External mechanical stress, environmental exposure, or manufacturing defects can cause cracks in the porcelain housing. Such damage can result in oil leakage and expose the internal insulation to air and moisture, further compromising the bushing’s electrical and mechanical integrity.

Online Bushing Monitoring

Offline or time-based testing programs for bushings provide only periodic snapshots of their condition, offering no assurance that faults or catastrophic failures will not occur between testing intervals. This inherent limitation calls for re-evaluation of reliance on traditional time-based diagnostic testing as the sole method for assessing bushing health.

On-line bushing monitoring in power transformers based on continuous measurement and phasor analysis of test tap leakage current has been around for 50 years. In recent years, due to an increase in substation monitoring, online bushing monitoring is also growing. This real-time approach is based on the principle of capturing and tracking high-resolution magnitude and phase data of leakage currents, enableing real-time monitoring of C1% and Relative Power Factor changes.

This methodology can be made more accurate by having an external voltage reference. The types of bushing fault conditions that can be detected include (but are not limited to): grading layer failure (C1% increase); moisture ingress (PF% increase); and the results of internal discharge (affecting both C1% & PF%).

These electrical characteristics serve as sensitive indicators of changes within a bushing’s dielectric system, enabling timely identification of deviations from nominal performance. By maintaining constant surveillance, online monitoring systems can effectively capture subtle shifts that may indicate the onset of degradation.

Measurements

The online bushing monitoring system involves the addition of high-resolution and high-precision ammeters at each bushing’s test tap, positioned between pin and earthed flange of the bushing. These ammeters measure currents that are directly proportional to the line voltage at the bushing, thereby providing crucial data on the condition of the insulation. The further chapters describe one of the standard methods of bushing monitoring and the measurements possible by using the total leakage current, measured at the test tap. Fig. 1 shows a typical condenser bushing’s C1 electrical structure that has a physical layer for C2 (controlled C2) by design of the bushing manufacturer. In this design the bushing monitor would be connected to the voltage tap and key electrical parameters monitored are capacitance (C1) and dissipation factor (tan δ), both of which provide insight into condition of the insulation system.

Dissipation Factor – DP (Tan Delta)

Dissipation factor, also known as tan delta, is one of the key parameters used to assess insulation health. This dimensionless quantity represents the phase angle difference between the applied voltage and resulting current in an insulating material, offering insight into dielectric losses.

Ideally, in a perfect insulator, current leads the voltage by 90°, implying no power loss. However, real-world insulators are not perfect and exhibit small amounts of leakage and dielectric loss. Capacitive current ID, resistive current IR, and total leakage currents can therefore be represented in a phasor triangle.

When measuring current at the bushing test tap, total leakage current is acquired, which is the vector sum (hypotenuse) of the capacitive (displacement) and resistive leakage currents “(1)”.

where:
– I_R: resistive current (in phase with voltage)
– I_D: capacitive current (leads voltage by 90°)
– I_T: total leakage current – the vector (phasor) sum (measured at the test tap)

Extracting the resistive component (IR) from the total measured IT in online bushing monitoring systems is challenging since it typically constitutes less than 1% of total leakage current. To measure a bushing’s absolute energy dissipation, the main lead voltage phase would be required, which is not measured in the approach described here. However, the phase between two test tap currents can be measured between phases A and B and A and C.

Measured current inter-phase angles at the test taps provide information on the relative change of δ; if both δA and δB increase by the same amount, the relative change will not alter. The relative change of each δ (A, B, and C) can be calculated from the measured angles in an arbitrary frame of reference.

In addition to the challenges stated above, it must be considered that ambient and operating temperatures will affect readings by causing fluctuations, especially of the resistive component. To allow accurate online tan delta monitoring of bushings, temperature compensation algorithms may be applied, referencing a baseline at 20°C, which helps ensure reliable analysis.

Change in Bushing Capacitance

Dielectric strength of a bushing is defined by the C1 capacitive layers, consisting of paper and foil meticulously wrapped around the central bolt conductor. Integrity of these layers is crucial for maintaining proper insulation properties. If a foil layer fails, the C1 capacitance would increase, leading to a corresponding rise in leakage current at the bushing test tap. This increase signals a potential degradation in a bushing’s dielectric properties.

Continuous bushing monitoring, based on measurement of bushing leakage current at the test tap, enables detection of changes in the capacitive layers. The amplitude measured at the bushing test tap can be approximated to that of the displacement current amplitude. Thus, for a given nominal operational voltage in the main lead of the bushing, the Capacitance C1 can be calculated using the calculated formula “(2)”.

where:
– I^D₀: capacitive displacement current (ideal behaviour)
– f: nominal operational frequency
– C: nominal capacitance
– V₀: nominal grid operational voltage

Since the I_D is directly proportional to line voltage, small fluctuations in system voltage will cause proportional changes in the leakage current. Additionally, capacitance values might change slightly with temperature, especially in oil-impregnated paper bushings, which adds fluctuations to the measurement.

Alternatively, the expected test tap current amplitude can be calculated using the operational voltage, nominal frequency, and the bushing’s nominal C1 again using “(2)”. The percentual measured current amplitude difference relative to the expected value can then be easily calculated. For a given nominal voltage V₀ and constant frequency f, this is also the C1 percentage change relative to its nominal value, allowing for the relative change of bushing capacitance to be easily calculated “(3)”.

Polar Plot

The polar plot is a 2D representation of a 3D set of variables using a nonorthogonal basis defined by three normalized vectors at 0°, 120° and 240°; i.e. it is the vector sum of three vectors of length 1 pointing at 0° (A), 120° (B) and 240° (C) each multiplied by its associated parametric value.

Thus, variations common to the parameter set of all 3 bushings, such as temperature fluctuations or power grid irregularities described earlier, are geometrically removed when plotted in the polar plot. However, if one of the 3 parameters changes with respect to the others, this will show in the Polar Plot and angle of the vector sum will indicate which value changed with respect to the others.

The polar plot approach is a highly effective tool for online bushing monitoring, offering a clear, relative, and intuitive view of the condition of 3-phase bushings by tracking phase angle and current vector changes over time. It is less sensitive to load and voltage changes, since it is based on relative deviations that are often more reliable versus looking at absolute values. At same time it provides a clear visualization of imbalance, indicating the affected phase and provide good tracking as the affected bushing’s vector moves outward (increased magnitude) and shifts in phase clearly visible on the plot.

Field Experience / Case Studies

The following presents customer case studies that illustrate the continuous and dynamic assessment of bushing health while the transformer remains energized.

Case 1: Bushing Power Factor Change

This case illustrates progressive insulation degradation, accurately detected by the online bushing monitoring, and clearly visualized using the Polar Plot.

This online bushing monitoring system was monitoring a 50 MVA Generation Transformer at a Solar Power Plant. In early 2019, online monitoring data revealed within a period of a month an increasing trend in the relative dissipation factor (tan delta) for one of the bushings on a three-phase transformer. This significant change of >1000% (relative value!) was visualized through both a time-domain trend and a polar plot, signaling the need for immediate investigation.

The rising trend in relative dissipation factor for Phase B, LV-side indicated increasing dielectric losses, most likely due to insulation aging, contamination, or moisture ingress. The change was significant compared to the other phases, ruling out system-wide environmental factors and confirming a localized issue. The polar plot confirmed this diagnosis visually, with Phase B clearly deviating from the cluster, reinforcing that the issue was confined to that specific bushing as shown in Fig. 4.

The line chart shows the evolution of the relative dissipation factor over time for all three phases (A, B, and C). Phase B (blue line) exhibits a significant and steady increase in dissipation factor beginning mid-February 2019, with sharp spikes peaking in March as per Fig. 5.

This case demonstrates the effectiveness of online dissipation factor monitoring as a predictive maintenance tool. By detecting subtle but critical changes in insulation condition, the utility was able to take pre-emptive action, replacing the degraded bushing before failure and thereby avoiding unplanned downtime and potential equipment damage.

Case 2: Relative Change in Bushing Capacitance

The following case shows a bushing save detected by the online bushing monitoring and clearly visualized on the Polar Plot.

The online monitoring system detected a sudden change in C1 capacitance of one of the bushings in the primary side of a 220 kV Generation Transformer.

Fig. 6 shows the time-series chart of the total leakage current I_T with stable baseline values across all three phases until beginning on November, when the measured current of phase B (green line) showed significant increase.

Fig. 7 shows the clear indication of the phase B bushing capacitance change by more than 10% without further necessity for the operator to analyze trend lines. Subsequently a controlled shutdown was scheduled to inspect the transformer and the suspect bushing.

Offline testing at 10kV confirmed abnormal capacitance levels for HV B phase bushing with a C1% increase of 17% from the FAT, respectively 9% change from the latest measurement during commissioning of the monitoring system, as shown on the Table 1.

Thanks to real-time monitoring and clear visualization of the capacitance trend, the utility avoided a potentially catastrophic failure. There was no unexpected service interruption, and the transformer remained in operation for an additional year before planned corrective actions, including a scheduled outage and bushing replacement program, were carried out.

Case 3: Bushing Power Factor Change

This case study examines the early stages of power factor degradation in a 364 kV substation transformer. The high voltage B phase bushing exhibits a noticeable change in relative dissipation factor (tan delta). Fig. 8 illustrates the increase in relative power factor, from 300% to 1200%.

Temperature dependency is a critical factor when assessing changes in the relative power factor of bushings during online analysis. As the insulation of bushings degrades from its original factory condition due to ageing, moisture, or other influences, there is often a noticeable correlation between rising temperatures and an increase in relative power factor.

In Fig. 9, trend lines of measured inter-phase angles indicate that AB measured value exhibits a stronger temperature dependency in relation to the top oil temperature (transformer load). This is clear that AB inter-phase angle trend line shows increased separation from other at elevated temperatures, and this behavior has been linked to B phase.

Conclusions

Bushing faults are inherently unpredictable unless subjected to regular monitoring. To mitigate this issue, implementation of online monitoring systems provides a proactive and continuous solution. These systems facilitate real-time observation of insulation performance without necessitating equipment shutdowns or manual interventions.

A notable advantage of online monitoring is its capability to identify slowly developing faults, which traditional periodic inspections often overlook. Issues such as gradual moisture ingress or localized overheating tend to evolve incrementally, potentially eluding detection until they reach advanced stages. Continuous monitoring enables the early identification of such trends, thereby supporting predictive maintenance strategies and minimizing the risk of catastrophic failures. As a result, online bushing monitoring signifies a critical advancement in enhancing the resilience and intelligence of asset management practices for high-voltage equipment.

Moreover, when integrated into substation SCADA or asset management platforms, online monitoring plays a pivotal role in digital substation and smart grid initiatives. It bolsters reliability centered maintenance (RCM) efforts and aids in reducing unplanned outages.

Bibliography
[1] Kane, C ; Golubev, A (2005) On Line Monitoring of bushing on large power transformers
[2] Cigre W.G A2.43 (2019) Transformer bushing reliability
[3] Picher, P ; Rajotte, C (2007) Cigre Field Experience with on-line Bushing Diagnostics to improve Transformer
[4] W. A2.34, TB445, “Guide for transformer maintenance,” Cigre, 2011
[5] IEEE Std C57.143-2012, IEEE Guide for Application for Monitoring Equipment to Liquid-Immersed Transformers and Components, IEEE Power & Energy Society, 2012
[6] K. Elmer, J. Lapworth, and M. Ryder, “Transformer bushing monitoring: Implementation and benefits,” in Proceedings of the IEEE International Conference on Condition Monitoring and Diagnosis (CMD), 2008
[7] R. Hartingsveld and P. van der Wielen, “Transformer Bushing Monitoring by Power Factor and Capacitance,” in TechCon North America, 2009
[8] H. Borsi and E. Gockenbach, High Voltage Engineering: Testing and Diagnosis, Springer, 2010
[9] J. D. Belanger and J. Jalbert, “On-line monitoring of high-voltage equipment: Practical implementation and case studies,” IEEE Transactions on Power Delivery, vol. 20, no. 1, pp. 425–432, Jan. 2005
[10] A. Behrendt, B. Harnisch, and M. Krüger, “Modern techniques for continuous monitoring of bushings and tap changers,” in CIGRÉ Session, Paper A2-104, Paris, 2006
[12] R. Brown, Electric Power Distribution Reliability, CRC Press, 2008
[13] Dr. D. Robalino, “Accurate Temperature Correction of Dissipation Factor Data for Oil-Impregnated Paper Insulation Bushings: Field Experience,” 2011

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Leer artículo en español

It is not unusual for utility engineers today to manage ‘fleets’ of overhead lines, some installed in the 1960s and 70s and now over 50 or even 60 years old. This time span is the center of the age range where overhead groundwires (OHGW) begin to fail but well before other components such as ceramic insulators and towers normally deteriorate.

Establishing end-of-life criteria for OHGW involves inspection of visual appearance and extent of corrosion. Concerns about the metallurgical condition of the steel wires are addressed with tests such as torsional ductility, which measures number of twists before wire samples break, as well as by measuring changes in tensile strength versus original ratings.

This edited past contribution to INMR by T&D expert, Dr. William Chisholm, reviewed the benefits and drawbacks of the various options should replacement be needed.

Izoelektro d.o.o.

Slovenia

Ningguo Songling Power Equipment Co.,Ltd.

China

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After receiving a report that an OHGW has reached its end-of-life, the utility engineer is confronted with decisions as well as multiple possible solutions, that include:

• Direct OHGW replacement with the same material and size of wire. This option may be easy to specify but calls for more difficult decisions when it comes to either scheduling an outage for an extended period or employing specialized crews for carrying out the replacement with live line methods. Whatever the choice, it is certain that such a replacement project will cost many times more than the original investment.

• A second option with high functionality could see substitution by an optical fiber groundwire (OPGW) system. With its multiple fibers wrapped around the central core, wire sizes and materials can be selected to best protect against charge ablation damage and moisture ingress over the long-term. By way of compensation for their higher cost, OPGWs offer utilities massive and highly marketable increases in point-to-point communications capabilities. The integration of utility optical fiber networks with local wireless, low-power-consumption networks could even become an incentive to live within view of a power line.

• Another option offering improved service performance would be to specify transmission line surge arresters at the same time that the OHGW is being replaced. Line surge arresters can be used to convert bottom phases temporarily to ‘under-built groundwires’ (or UBGWs) that reduce voltage stress under lightning conditions. Unlike copper grounding systems at the tower base, such UBGWs are always secure against theft and corrosion.

• Yet another solution could be termed the ‘leave it empty’ option. This would see the OHGW removed but not replaced. The same lightning protection could then be achieved by fitting line surge arresters of sufficient energy rating. Any lightning ablation damage normally occurring on the OHGW would then transfer to the aluminum phase conductors, perhaps shortening their residual service life or requiring more frequent inspections. While the role of the OHGW in managing fault current on power systems is important, this function can equally well be provided with adequate grounding at each tower and with reduced fault duration through improved relays and switchgear. Balanced against these drawbacks are benefits such as reduction in flashovers from excess sag or relative conductor motion under icing conditions. There is also a reduction in induced current losses meaning greater energy efficiency.

• The ‘replace with something smaller’ option could put a replacement OHGW or OPGW below rather than above the phase conductors. Primary lightning protection is then transferred to line surge arresters installed on all upper phases. Permanent UBGWs are easier to install below the phases. Also, in this position they continue to provide low, multiple-grounded impedance to ground for managing fault currents. Greater overturning forces associated with reduced UBGW height as well as ease of access to any optical fibers are the additional benefits with this option.

Utility engineers should recognize that when OHGWs fail, the situation also offers valuable resource options to consider when making the best decision on how to handle the need for replacement.

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Unless properly mitigated, overvoltages could exceed specified insulation withstand levels, leading either to a reduced lifetime of a component or to insulation degradation, potential dielectric failure and long repair times.

The post Switching Overvoltage Stresses on Sheath Voltage Limiters Due to Cable Circuit Energization (Video) appeared first on .

Wenzhou Yikun Electric

China

PFISTERER

Germany

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Development of medium voltage distribution level interconnected photovoltaic (PV) generation systems has increased significantly and now is nearly as common as small-scale building level PV systems. These larger systems range in size from 2 MW to 30 MW and connect to utility distribution lines ranging from 12.47 kV to 34.5 kV in typical U.S. applications. While utility scale systems offer lower implementation costs per kW than small-scale PV systems, a significant capital investment is still required.

These systems typically include installation of new overhead distribution lines, disconnect switches as well as metering and protective devices. Common design practice sees these devices each mounted on their own pole prior to the underground service riser that connects to the PV system interconnecting switchgear. From the switchgear, a collector grid of underground cables is used to interconnect each PV step-up transformer. Each step-up transformer connects to one or more PV inverters, which convert DC PV power to AC power for injection into the utility grid. This typical design topology, shown in Fig. 1, includes several surge arresters within the power path (medium voltage, low voltage and DC).

It is notable that on the overhead line sections, many surge arresters are used sequentially, one per power pole. The interconnecting switchgear includes surge arresters, and each collector grid cable has a single set of surge arresters on the last PV step-up transformer. All PV transformers between the interconnecting switchgear and the last transformer in the collector grid include no surge arresters since each transformer feed-through connection is occupied by an interconnecting cable. Using a case study of an actual system, the following sections review a typical design strategy by modeling the system in EMTP-RV and evaluating the protective ratios for alternate arrester placement, ratings and configurations.

System Parameters

The 10 MW PV system is interconnected to an existing 34.5 kV overhead distribution line. As shown in Fig. 1, the interconnection includes several pole-mounted devices, each including a set of surge arresters. Two additional arrester sets are included, one at the switchgear and one on the last transformer. The following table summarizes the arrester ratings for the system.

The distribution system is solidly grounded, as per the utility standards, and is not designed for islanded microgrid operation. Each 2 MW PV inverter skid and step-up transformer is located remotely from the main switchgear, and power is supplied via a collector grid of 1/0 Copper 34.5 kV cable, with a total length of 1550 ft (472 m). Only Transformer 4 includes an elbow mounted lightning arrester. On the secondary side of the transformer, each inverter skid includes AC low voltage surge protection device (SPD) and at the inverter MPPT inputs DC SPDs. AC and DC SPDs were a selected option for purchase from the inverter manufacturer per standard practices. DC combiner boxes did not include DC SPDs.

In order to evaluate the effectiveness of the typical arrester design approach, a direct lightning stroke is modeled on the incoming overhead line at the interconnect pole. The surge current is 20 kA using the standard 8/20 µs wave shape in the following form:

where; Im = 20kA, α = -72274/s and β = -98417/s. The surge is timed to start at the peak phase-a voltage.

Each equipment Basic Insulation Level (BIL) is indicated below, as are the required protective ratios (PR).

where the PR is calculated as:

The equipment will be considered adequately protected if the PR ≥ 1.15.

Design Configuration

Considering that each utility pole includes its own arrester set, the analysis reviews the collective benefit of installing all four arresters, sequentially added, one-by-one, down to the final most distant transformer in the collector grid. The analysis first reviews the overhead line system, then includes the PV generation system using this sequential approach.

Pole Mounted Arresters

As shown in Fig. 2, each pole includes both pole-mounted equipment and identical arresters. Each pole is separated by 30 ft (circa 9 m) of overhead line and it is not possible to partially disconnect the overhead line segment or operate the system without the line sections with equipment in service.

This configuration is widely adopted in PV systems of this size range, however alternate configurations utilizing pad-mounted fault interrupters are used which combine the disconnect, metering and arresters in one package, or utilizing a single set of arresters only on the interconnecting pole. In this configuration, during periods of PV system maintenance or if the utility requires the system to be separated from the utility, the rise pole disconnect switch would be open.

To evaluate the relative effectiveness of the arrester system in this configuration, a direct lightning stroke on the incoming line at the interconnect pole is modeled with no arresters. The effect of the 20 kA stroke results in a 350 kV surge voltage at the main switchgear, which is significantly above the BIL rating of the 34.5 kV equipment and certainly justifies installation of arresters in the system.

Considering the interconnect pole is nearest to the interconnecting overhead line system, the first analysis includes arresters at the interconnect pole, successive analysis runs, each adding an arrester on the next pole closer to the PV generation system, are presented. Initially, results are provided for the voltage surge assuming the PV generation system is disconnected. V_peak is reported at the location within the system that experiences the highest surge voltage. In most cases, the protective ratio is adequate to provide protection for the distribution equipment. It should be noted that the lower ratings of arresters in this system could have been used, which would increase the protective ratios.

In this configuration, during periods of PV system maintenance or if the utility requires the system be separated from the utility, the rise pole disconnect switch would be open. During normal operation, the riser pole disconnect would be closed and additional arresters would be part of the electrical circuit.

PV Collector System Arresters

Once the riser pole disconnect switch is closed, the PV system main switchgear is energized and this adds a new set of lower kV rated arresters to the system. Moreover, when the PV system collector grid is energized, the transformer primary arresters also contribute to the system protection.

Sequentially adding the switchgear arrester, the final transformer arrester then results in the following protection ratios:

It is notable that the peak voltage at transformer 1 is 91 kV while the peak voltage at transformer 4 is 86 kV. The peak transformer secondary voltage at transformer 1 is 23 kV and 21 kV for transformer 4 without the SPD at the inverter input, which is well within the transformer’s capability.

PV Inverter SPDs

When the inverter is in service, the low voltage AC system is protected by the inverter’s Type II SPD located at the inverter’s incoming AC section. Since the voltage surge at this point in the system is approximately 20 kV, and the inverter is rated for 2.5 kV it is justified to select AC SPDs at each inverter’s output as recommended. The inverter also includes a Type II DC SPD located on each of the DC inputs. Lightning strikes on the PV field itself are modeled similar to that of the AC side.

The following table summarizes the results of the inverter voltage surges.

In this typical system, the DC collector grid includes a network of DC combiner boxes with average cable length of 400 ft (122 m) from combiner to inverter. While combiner level SPDs are recommended, they were not used in this application and the resulting voltage surge at the combiner boxes is 2.2 kV, which is within the system’s capability.

Results

It is apparent that a single arrester at the interconnect pole can protect the equipment but is insufficient to pass the protective ratio criteria. However two or more arresters in the system easily provide adequate protection, though there are diminishing returns by adding additional arresters. It is also apparent that AC SPDs are required at the inverter AC output since the power electronic equipment is not rated to withstand voltage surges that are similar to that of a transformer. Several common questions exist surrounding placement, rating and quantity of arresters in this design configuration. These are evaluated below.

Alternate Design Configurations

This section evaluates common alternate configurations of the same basic PV generation that employ fewer arresters, alternate ratings and alternate arrester locations.

The most common alternate configuration is to remove the multiple pole- mounted arrester system and install a single set of arresters at the interconnect pole. Traditionally, the main switchgear includes a set of arresters and a single set of arresters is placed at either the first or the last transformer in the collector grid.

Transformer secondary arresters and DC arresters are recommended at the inverter skid and are commonly applied. It is apparent that utilizing an interconnect arrester with an MCOV rating greater than the system L-L voltage will not pass the protective criteria (as previously indicated). Therefore, to use a single arrester set at the interconnect pole an alternate arrester rating is required. In this case, with the utility system being solidly grounded, the traditional arrester rating would be 30 kV and 24.4 MCOV. Using this selection, the system is protected.

It is notable that placing the transformer arrester closest to the incoming overhead line adequately protects transformer 1 but transformer 4 experiences much higher voltages. In this case, transformer 4 is still protected, however if the incoming line arrester was increased to 45 kV 36.5 kV MCOV, transformer 4 would experience 133 kV and a PR of 1.13. This brings to light a key decision point. In order to economize the arrester design, the arresters must be sized according to the system grounding configuration and the projected operating modes. In cases where the utility system is solidly grounded, and the PV system is not required to island the collector system, the arresters can be sized for a solidly grounded system and less arresters can be used. However, if the system is intended to island, and the collector system during island mode is not effectively grounded, the arrester ratings must increase to avoid Temporary Overvoltage (TOV) damage. This would increase the arrester ratings, and may result in additional arresters being required to bring down the voltage surge and increase the PR. In the evaluated cases, the optimal location for the collector grid is at the end of the cable system on the last transformers primary. The transformer secondary voltages are within the transformer systems ratings in each case.

As previously noted, the inverter AC output requires a Type II SPD to protect the power electronics. In all cases, the transformer primary arrester is by itself insufficient to protect the inverter. The remaining design alternative is to add DC SPDs within the combiner boxes in addition to the DC SPDs required at the inverters. Utilizing SPDs at both inverters and combiner boxes results in a reduced voltage surge at both the inverter and the combiner yielding 1.2 kV and 1.5 kV surge voltages respectively. The addition of combiner SPDs may be required if metering equipment is located in the combiners and a lower surge voltage limit is justified.

Conclusions

As with most designs, many different solutions are available to address lightning protection concerns. Careful evaluation of the system and its grounding methodology must be undertaken to ensure proper insulation co-ordination.

Specifically, the following items should be considered:

1. Confirm system grounding and apply surge arresters and SPDs with ratings appropriate for the service voltage. This must include both island mode cases (if applicable) and normal mode.

2. Performing an insulation co-ordination study to determine the proper SPD and arrester locations utilizing standard design templates can result in overdesign and increased costs.

3. Locate the collector grid arrester at the last transformer in the collector.

4. Provide inverters with Type II SPDs on AC output and DC input.

5. Evaluate the DC system including combiner boxes and, if needed, apply SPDs specifically designed for PV systems at combiners.

References
[1] Littlefuse, “Surge Protection for Photovoltaic Systems,” 2019.
[2] J. Das, Transients in Electrical Systems, McGraw Hill, 2010.
[3] NFPA, Standard for the Installation of Lightning Protection, 2014.
[4] e. a. Nor Izzati Ahmad, “Analysis of Lightning-Induced Voltages Effect with SPD Placement for Sustainable Operation in Hybrid Solar PV-Battery Energy Storage System,” 2021.
[5] J. Woodworth, “Understanding Temporary Overvoltage Behavior of Arresters,” 2017.

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This past overview combined an edited contribution by retired Prof. Stanislaw Gubanski of Chalmers University of Technology in Sweden with excerpts from past issues of INMR.

Hitachi Energy Transformer Components and Service

Switzerland

Hivolt Power System

China

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Like a surge arrester, a bushing is a relatively low cost component ensuring the safe operation of a high value asset. While bushings account for only about 5% of the cost of a power transformer, their catastrophic failure can lead to total loss of the transformer and possibly other expensive equipment as well. Certain types of bushings can threaten not only substation personnel but even nearby communities.

In their early years, bushings were little more than hollow porcelains filled with transformer oil or solid resin surrounding the conductor. Such simple bulk and solid type bushings are in fact still being applied at medium voltage levels. But as networks have become more sophisticated, the need was recognized to better distribute the electric field generated across a bushing – especially at higher voltages. This resulted in designs that were capacitance-graded. The basic principle was to distribute the natural field between conductor and earthed flange by employing intermediate conductive layers radially (to lower the field at the conductor and better utilize the insulation material) and also axially (to allow for higher flashover voltage values for a given arcing distance).

Originally, materials used in the cylinders wound around the conductor included resin-bonded paper and carbon materials. These were later modified to designs involving less conductive grades of paper along with aluminum foil. One of the motivations behind development of field-graded bushings was reducing the diameters required for the porcelain housings. On ungraded bushings, electric field tends to be concentrated around the flanges and therefore risk of breakdown becomes high. On fine-graded bushings, stress is linearized and spread over more distance, resulting in greater safety margin. For example, the porcelain housing diameter on a simple 110 kV field-graded bushing is about 240 mm measured across the sheds. But to handle the same stress, an identical ungraded bushing would need a housing of almost double that diameter. The benefits of narrower external diameter translate into lower cost for the housing, reduced weight, less oil and less clearance diameter of the embedded shielding in the lower part.

The basic principle in bushing design consists of a conductor surrounded by an insulating solid cylinder that is mechanically fixed to the earthed barrier. As discussed, distribution of electric field inside such a construction, is highly non-uniform in terms of both axial and radial components. The highest stress concentration appears at the so-called ‘triple junction’ between the earthed wall, the insulating cylinder and the gaseous or liquid medium outside the bushing body. This localized high concentration of stress can trigger the onset of partial discharges, sometimes referred to as ‘gliding discharges’ since they have a strong capacitive coupling to the bushing’s internal conductor and therefore proceed along the insulating cylinder’s surface. They can lead to tracking along the bushing and even result in flashover. Initiation of gliding discharges as well as their subsequent development becomes easier when the unit capacitance of the insulation (i.e. across its thickness) is greater. Therefore, the voltage level for their ignition and propagation (virtually equal to flashover voltage) is determined by this parameter. This stands in contrast to other types of discharges, where the typical controlling parameter is electrode separation distance.

Given these considerations, the best way to increase a bushing’s flashover withstand voltage is by improving electric field distribution along its surface. In the case of higher voltages, the most effective means to achieve this is through capacitive control for AC applications and resistive control for DC applications. Capacitive control is based on inserting metallic screens into the solid insulation of the bushing, essentially forming a system of in-series connected capacitors whose magnitude depends on geometric arrangement. Perhaps the most frequently used and effective solution is when series capacitances are maintained at equal levels. Fig. 1 illustrates the impact of modifying field distribution this way.

Inserting metallic screens during manufacture of a bushing used to be demanding and labor-intensive but modern core winding equipment has made it highly automated. In the case of paper insulated bushings, metallic foils are inserted between the different paper layers. Choosing the appropriate radius and length of these screens allows for the desired series capacitance. Optimal resistive control of electric field distribution in the case of DC bushings usually involves covering the critical region near the electrode with semi-conducting layers. The aim here is to increase resistance with increasing distance from the earthed electrode.

Alternative Bushing Technologies

In the case of bushings for higher system voltages, there have traditionally been three main types of insulation system used: oil-impregnated paper (OIP), resin bonded paper (RBP) and resin-impregnated paper (RIP). New resin-impregnated synthetic (RIS) types, without oil, have also been developed and are finding growing application.

OIP Bushings

Since the main insulation of substation transformers has been based on oil-impregnated paper, this same insulation philosophy has carried over and become the most commonly used technology for constructing bushings. In fact, it is estimated that up to two-thirds or more of all installations of a bushing on a power transformer involve an OIP design. In certain markets, such as China and the United States, this proportion is probably even higher. This market preference for OIP style bushings has been maintained over the years due to a variety of refinements made by some of the leading manufacturers. These improvements have allowed the technology to remain attractive both to intermediate bushing customers (i.e. transformer OEMs) and also to final users, in spite of changing needs and requirements. For example, some bushing suppliers offer standardized high creepage porcelains on all OIP bushings they sell. The goal was to allow the same bushing design to be used across a variety of service environments and thereby reduce the need for end users to stock many styles of replacement units. It has allowed bushing manufacturers to streamline their own ordering and inventorying of porcelain to reduce unit cost as well as production lead times.

Similarly, over the years OIP bushing suppliers have made design changes aimed at reducing the diameters of porcelain housings to make them slimmer and lighter. This has suited transformer manufacturers who prefer bushings that are easier to handle during transport and installation. Slimmer profiles have offered benefits apart from reduced weight: firstly, the porcelains themselves carry lower cost since decreased diameter significantly reduces purchase price; secondly, slimmer designs mean the volume of oil within bushings could be correspondingly reduced. With this has come progressively less concern about risk of leaks and fires.

Apart from these types of design changes on an industry-wide basis, various individual OIP bushing suppliers have made additional improvements: better methods to seal against leaks; designs to facilitate horizontal or vertical mounting; better visual monitoring of oil levels; easier interchangeability between transformer and switchgear applications; and better mechanical contacts between top terminal and conductor to avoid the potential for heating should the conventional threaded contact weaken. Other refinements have also been developed that allow OIP bushings to be changed out quickly in the field with minimal impact on operation of affected apparatus. Due to competitive forces, these innovations have been matched by others in the industry with the result that most suppliers offer improved versions of OIP technology.

One of the areas within this technology where there could be growing interest for further development is improved condition monitoring. There are hundreds of thousands if not millions of OIP units operating worldwide and one question is how intelligent such a design should be, especially in regard to internal monitoring of oil level and other service parameters. Still, given the many refinements made to these designs over the years, it seems unlikely more can be done to enhance performance and functionality or further reduce cost. Indeed, this style of bushing has reached a state of design maturity with limited room for further optimization.

Resin Bonded Paper (RBP) Bushings

Manufacturing RBP bushings has been based on winding layers of resin-coated paper around the conductor under heat and pressure to laminate the layers together. This process is inherently difficult to control and therefore such designs have suffered relatively large numbers of failures over the years due to voids and other defects. In spite of this drawback, however, the RBP bushing style has found a market because of price. Presently, use is limited mainly to lower voltage levels since risk of thermal instability and even runaway due to dielectric losses in the paper is comparatively high. For this same reason, operating radial stress in such designs is usually maintained at around 2 kV/mm, lower than for other bushing types.

Resin-Impregnated Paper Bushings

Compared with RBP bushings, significant improvements have been achieved by introducing a technology whereby the paper insulation is impregnated with epoxy resin and then cured. The resulting insulation system, containing field grading elements, is dry and void free. This technology involves higher material as well as product costs but offers benefits such as being non-combustible, providing an impregnable seal for the transformer tank, being easily machined to required dimensions and remaining unaffected by ambient humidity. Moreover, when equipped with a composite housing, there is no risk of explosive shattering. Great care, however, has to be taken during the curing cycle to avoid internal stresses and formation of cracks – especially as volumes of material increase for high voltages. Typical radial operating stress in RIP bushings is around 3 kV/mm.

RIP bushings have no dynamic processes occurring within their cores and therefore offer long service lives. Other advantages include eliminating any risk of leaks or explosive failure of an oil-filled component. Over the years, incidents of exploded OIP bushings resulted from excessive operating temperatures when cooling systems failed on transformers operating at 100% load. Even if not leading to an explosion, situations such as this can still shorten the effective service life of an OIP bushing to as little as 10 years. While a normal OIP bushing can operate well up to 105°C, an RIP style can deal with temperatures greater than 120°C. Indeed, testing by suppliers has confirmed that thermal ratings for RIP bushings are considerably higher than for OIP equivalents. This superior thermal behaviour is an advantage in utility markets where transformers are being run at high load.

Apart from thermal advantages, RIP bushing technology is viewed as the way forward simply because it offers a dry solution. In spite of successive refinements made to OIP designs, their most important drawback remains because it revolves around the presence of oil. Typical problems have included leaks due to worn out seals, excessive filling of reservoirs in horizontal mount applications or unusually high operating temperatures. These types of bushings also suffer from greater vulnerability to lightning strike or other factors that can trigger explosive failure. Similarly, moisture ingress presents a constant and potentially severe problem. Finally, in the case of connection to SF₆, presence of oil is undesirable due to the consequences of leaks. All these drawbacks favour a dry bushing technology such as RIP. Indeed, there seems an accumulating trend toward dry bushings that is reflected in a steady rise in its share of the total graded bushings business. Further increases are expected due to application-specific advantages of RIP technology. For example, the OIP design for oil-to-gas connections is cumbersome and difficult to maintain while the RIP alternative is a comparatively easy technical solution. RIP technology also offers important advantages in the area of oil-to-gas and oil-to-oil applications.

As with OIP technology, suppliers of RIP bushings have sought to incorporate product refinements to justify the higher price normally associated with this technology. Among the most important developments in this regard has been application of silicone housings in place of the porcelain that still dominates OIP bushing installations. This technical solution is viewed as the ultimate in bushing design and performance. There is no doubt that market acceptance of silicone housings on a bushing has been far greater for RIP than for OIP designs to the extent that probably more than 90 per cent of all graded bushings that are silicone-housed have RIP cores. This is because the real advantages of silicone material are most evident to customers when applied to this technology and in some respects even help RIP better compete against OIP styles. Germany, Switzerland and Austria are examples of markets where dry bushing technology incorporating silicone housings is widely accepted due to safety and environmental concerns.

The motivation behind transition to silicone in place of porcelain as a housing for bushings has involved factors such as reduced risk to people and apparatus, better pollution performance, easier handling and faster production lead times. Bushings can be especially sensitive to pollution since they are often inclined or located under roofs – situations that can lead to uneven deposition of contaminants. A bushing then becomes more vulnerable to flashover and in such cases silicone is preferred to porcelain. Other application conditions can also make a bushing more vulnerable to pollution and favour a silicone housing over one made of porcelain. However, one of the challenges in replacing porcelain with silicone on an RIP bushing has been cost, especially at voltages below 245 kV where much of the volume is focused.

Slimmer diameters of RIP units compared to most OIP designs have also meant that the porcelain shells being replaced are less costly, only accentuating the price difference. An early problem when it came to changeover of external insulation away from porcelain was that the new silicone insulators were often specified as a one-for-one replacement for porcelain. This meant that the larger flanges required for porcelain were also specified for the composite alternative, even though not strictly necessary. This has become less an issue since bushing suppliers and users have both grown to understand the need to optimize the entire design. Moreover, the growing level of standardization in this industry has resulted in sizes and diameters of fittings becoming more uniform.

Among the notable developments when it comes to application of silicone housings to dry bushings – both RIP & RIS styles – has been a process that sees sheds molded directly onto the cured core. This technology has been available for many years and is best suited up to a maximum voltage. The principal advantage is cost reduction because direct molding eliminates need for the FRP tube as well as the dielectric material that fills the space between core and tube. Notwithstanding cost advantages, application of direct molding onto RIP cores has not achieved widespread use. Apart from the investment needed by the bushing manufacturer to be able to implement this process in-house, there are technical issues, especially at higher voltages. For example, there must be an extremely good chemical bond between core and silicone to avoid any possibility of interface problems. There is also the issue of ‘cold switch-on behavior’. When silicone rubber has been molded directly onto the RIP core, vapor will likely have migrated through the material before energization and could be absorbed by the resin body. This could mean that, at least initially, the bushing will have a higher dissipation factor.

Another potential drawback of direct molding relates to mechanical function. If the mechanical requirements of the bushing exceed those of its RIP core and conductor, the added mechanical strength of a tube will be necessary to help carry the load. A tube also offers the benefit of providing a barrier against moisture. In this regard, it may not be appropriate to draw a parallel between mold-on silicone bushings and experience with polymeric arresters that have experienced growing use of direct mold technology. Arresters are not intended to last 30 to 50 years and, if they fail, it is often not a serious problem. If a bushing fails, the whole transformer is in trouble.

Apart from external insulation, there do not appear any major developments in the way RIP cores are produced that might significantly reduce cost. Drying and curing cycles are critical steps and cannot easily be shortened. Nor has the resin that forms the body of the RIP bushing changed significantly. Indeed, rather than looking at changes in the resin body itself, suppliers have typically looked for optimized production logistics. The entire process for manufacturing these bushings is technically demanding, particularly as voltage levels climb, and this has limited the number of qualified suppliers. Whatever practical refinements are still to be made to RIP bushing technology will likely be in such areas as better grading of the condenser layers to make them progressively smaller and more efficient. There may also be improved process control to improve robustness of manufacturing, making it a more repeatable process that results in a consistent product every time. A void the size of a pin hole can result in an entire RIP core being relegated to the scrap heap. There is no possibility to recycle the material since it is a thermoset resin that cannot subsequently be melted down.

In the end, a purely technical comparison between OIP and RIP bushing technologies may not be the decisive factor in customer preference. Given the role of commercial considerations in purchase decisions, success will go to bushing suppliers who offer the most features for the price, irrespective of technology. These include creepage distance, seismic capability, cantilever strength and total interchangeability for application on transformers or breakers, among others. Similarly, not everyone in the industry is convinced that RIP is always the better choice. This technology comes with disadvantages that must also be considered – from higher price to greater uncertainty about how the core is ageing. This is because, unlike the case for OIP styles, reliable ageing analysis on an RIP bushing cannot be performed in the field. Rather, the unit has to be removed from service and returned to a laboratory for testing. Given the power utility environment, there will always be concerns about how bushings are ageing. For this reason, some predict that the tendency for new bushing types may be more oriented toward gas-filled or gas-impregnated units in place of those relying on organic dielectrics.

Other Designs & Considerations

In contrast to longstanding OIP, RBP and RIP bushing technologies, more and more designs today make use of pressurized gas, predominantly SF₆, as internal insulation. Metallic screens are used for controlling electric field stress inside the bushing body. As discussed, selection of the external housing of the main insulation in a bushing is one of the key factors affecting service performance and cost. For indoor applications with low contamination and normal humidity, resin-based RIP solutions do not require an additional housing over the epoxy core. This is not the case, however, for either OIP or gas-filled bushings, both of which require porcelain shells or composite insulators. For safety considerations, application of the composite solution is often preferred when considering a gas-insulated unit under high internal pressure.

Another way to categorize bushing technologies available today relates not to commonalities in design and construction but rather to main areas of application or applicable voltage levels. Probably the most common application of bushings is on power transformers, where the outer parts operate in air, other gas or oil. OIP bushings are currently available up to 1200 kV while capacitance-graded bushings with epoxy resin impregnated insulation have been developed up to 1000 kV. Apart from UHV, another specialty application includes high current bushings (i.e. with operating currents up to 40 kA) used on the low voltage side of transformers and also in generators. One of the key design requirements here is capability to effectively dissipate heat.

Another broad group of bushing applications involves connections to gas-insulated switchgear (GIS), most typically as entrance bushings. RIP based condenser cores embedded inside a porcelain housing or composite tubes with silicone sheds both function well in this regard. For the gas part, a discharge resistant surface varnish is necessary to fulfill the requirement of resisting corrosive by-products from decomposition of SF₆. In addition, requirements for direct connection between transformer and GIS are becoming increasingly common and special designs of oil-to-gas bushings have been developed for this purpose.

Yet another growing application – especially in countries such as China, India, Brazil, South Africa, Norway and Canada, among others – relates to HVDC converter stations. Nowadays, manufacturers offer special bushings for connecting to HVDC transformers, reactors or air-insulated system components up to ± 800 kV DC and higher. These can operate in a transformer oil environment, indoors or for any outdoor connections. As discussed, in contrast to high voltage AC applications, the performance of an HVDC bushing is influenced by the resistive properties of its materials and therefore stress control must be appropriately adjusted. For example, it is important to control the field in the oil part of an OIP HVDC bushing since the ratio between resistivity of paper and that of oil can be as high as 104. Use of composite insulators in the design of bushing shells for the highest voltage levels provides not only superior flashover performance but also high mechanical withstand. Another issue relates to the dynamics of charging under DC. This remains an important factor to take into account – not only during testing but also in terms of impact on flashover performance, especially during voltage reversals. Yet another factor to consider in UHV bushing applications relates to better understanding ageing of polymeric materials in such an environment.

The tendency towards increased transmission voltage levels and the resulting growth in dimensions of bushings has also made it necessary to better control parameters such as seismic behavior. Historically, several methods have been used to verify seismic capabilities of bushings. These involve static calculations to estimate the forces generated during a seismic event with a given ground acceleration and then comparing this against design capabilities of the equipment. Although IEEE and IEC standards involving shake tables have been used to qualify equipment for seismic areas, past earthquakes indicate that transformers and bushings that passed these tests can still sustain significant damage. To overcome this deficiency, numerical simulations have been developed and refined.

Conclusions

Development in bushing technologies has been impressive if not always obvious. Bushings today might look much like those of the past but there have been subtle refinements and improvements in scale, functionality, performance and cost. Among the driving forces behind this progress have been ongoing efforts by the industry to reduce costs as well as production lead times and standardize bushings to reduce need for users to stock many different types of spares. Moreover, internal competition between OIP and RIP styles has also pushed suppliers to seek optimization in both designs.

Another driver in development of bushing technology, especially in recent years, has included growing use of HVDC based transmission as well as increases in UHV AC voltage levels. At the same time, environmental demands for developing oil-free as well as low or SF₆-free high voltage substations are creating new design challenges for the industry. Today, manufacturers have developed and already offer bushings for voltage levels exceeding 1000 kV and for high rated currents. On the HVDC side, work on developing ±1000 kV bushings has progressed.

RIP bushing technology seems well understood and this allows production of partial discharge-free condenser bodies, even for extremely large units. Increased use of new gas compositions (e.g. N₂/SF₆) in GIL will require elaborating new design criteria. Finally, growing application of silicone housings in bushing designs has created the need to further study their long-term behavior – especially under combined DC voltage, thermal and mechanical stresses.

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Simplified models of lightning backflashover and transient grounding allow quantitative insight into relative performance of alternative treatment options.

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