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Protecting substations from lightning and switching surges that lead to insulation flashover has been a key issue for as long as there have been power systems. While this need has remained constant over 100+ years, options on how best to mitigate high voltage stresses have changed substantially.

This edited past contribution by arrester expert Jonathan Woodworth, presented an overview of different scenarios, available options and the rationale behind each specific case.

DALEKOVOD OSO

Croatia

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Considerations in Substation Protection

Considerations in the protection of substations are listed and covered below showing different performance criteria:

Failure Rate

This is the acceptable number of insulation failures over the service life of the station. A station is typically designed according to some quantifiable performance levels, as outlined in Section 3.4 of IEC 60071-2 and in IEEE 1313.2. Moreover, IEC 62305-2–2010 identifies tolerable risks for a substation, where risk level is affected by different types of service loss.

Required Insulation Withstand Level (U_rw)

This is given in terms of surge types such as fast, very fast, slow and temporary overvoltages.

Safety Margins   

The safety margins typically used in substations are 15% for transformer windings and 5% for air insulation.

Separation Distance

This is the distance between arrester and intended protected equipment. If too great, voltage at the protected equipment could exceed its required insulation level due to reflections and traveling waves.

Open Breaker Protection  

Breakers in the open position leave the line side bushing of the breaker 100% unprotected if arresters are not installed at the line terminal. While this is a low probability issue, for critical stations protection of an open breaker can be important.

Altitude

Surge performance of insulation at a substation is highly dependent on elevation since insulation withstand voltage reduces by ~11% with every 1000 m increase in altitude. Because of this, longer insulators are required at higher elevation and arrester protection becomes ever more important. The arresters themselves are sometimes also required to be longer due to power frequency requirements.

Insulation Type

Some insulation can withstand flashover without damage and some cannot. Insulators in air are a self-restoring type insulation that depends on surrounding air for its insulation capability outside the insulator body. But should voltage stress in the air exceed its withstand capability, the insulator experiences flashover failure. Nevertheless, once the flashover is cleared, the insulator holds off line voltage as it did before the surge. Post insulators, tension insulators, bushings, switch stand off bushings and cable terminations are all examples of different types of self-restoring insulation. By contrast, transformer windings and all oil/paper type insulation cannot recover from a disruptive discharge and are therefore considered non-self-restoring insulation. Once failure has occurred in such non-self-restoring insulation, the transformer will need to be refurbished or replaced. Other types of non-self-restoring insulation include underground cable, CCVT internal components, PTs and CTs.

In the process of protecting substations, the type of insulation dictates level and cost of mitigation applied to provide proper protection such that non-self-restoring insulation is generally protected at greater effort and cost.

Assets Requiring Surge Protection

A power transformer’s primary winding is universally protected at the transformer using arresters. This is because the transformer is typically the highest value asset in a substation and often has the lowest surge withstand voltage. It can be stated with confidence that 99% of all power transformer primary windings in outdoor air insulated substations are protected by arresters. The secondary windings are the second most universally protected insulation in a substation equipped with a power transformer. These windings are not quite so exposed to surges and thus are protected with arresters perhaps only about 75% of the time.

Transformer Bushings

Both primary and secondary transformer bushings are protected by default using the same arresters that protect transformer windings. If the transformer neutral exits the transformer through a bushing and is connected to a neutral grounding resistor, grounding resistor and bushing should both be considered for protection by an arrester.

Cable Terminations

Cable terminations within a substation are often paired with arresters. But the protection in this case is more for the cable since the termination itself is self-recovering type insulation while the cable is not. Should cable insulation become damaged from a surge, repair of that asset will become a costly task.

Breaker Bushings & Longitudinal Insulation

Breaker bushings and internal longitudinal insulation between contacts are also high value assets within a substation. Yet these are typically not as well protected as are power transformers, but should be. More on this below.

Metering Equipment

Voltage monitoring CCVTs and PTs are high in value and, if present in a substation, their protection priority should be considered high. When designing substations, these devices are sometimes located where they actually become part of the protection scheme due to their capacitance.

Shunt Capacitor Banks

These can absorb significant charge from a lightning or switching surge without damage. Therefore, if a bank contains many MVar, it is not likely in need of surge protection. Smaller banks, however, may not be able to take a large surge without over charging and flashing over, so they often need protection. Whether the bank is large or small, need for arrester protection of the system from the bank should also be evaluated.

Surge Sources & Mitigation Methods

Direct Lightning Strike to Substation

Direct strikes to substations do occur although it is rare that a flash makes a direct hit on equipment. This is because stations are universally protected from these by overhead shield wires or masts. For example, shield wires are situated above the equipment and around the perimeter such that they intercept any strike and transfer it to earth. Still, even though a direct strike is averted, the possibility exists that an induced surge will make its way to equipment. Where insulation withstand voltage is greater than 350 kV, it is not likely that flashover will occur from an induced surge. But if insulation withstand voltage is less than 350 kV arresters are needed to protect equipment from induced surges.

If masts are used, these are situated strategically so that all direct strikes will hit them instead of the equipment or bus. The most suitable standard for designing and quantifying effect of substation shielding is IEEE 998.

Lightning Surges on Incoming Lines

The only way for a potentially damaging lightning surge to challenge a substation is by entering on an incoming line. If the incoming line is shielded, there needs to be a backflash not too many spans from the substation to a phase conductor for the surge to pose a problem. When a backflash occurs at a tower, it produces a very fast rising surge. But as the surge travels down the line, the corona on the line reduces the traveling wave-front steepness such that by the time it reaches the station it has become manageable.

But if the backflash occurs only a span or two away, the wave-front steepness of the entering surge is extremely high and will significantly stress insulators in the substation – even when arresters are installed. Fortunately, substation arresters seldom see more than 10-15 kA of current from a backflash on an incoming line. As a result they are not thermally stressed by lightning, only electrically stressed.

Switching Surges on Incoming Lines

Switching surges on incoming lines are the most common type of surge to reach within a substation and can travel hundreds of kilometers due to their low frequency relative to lightning. When these types of surges enter, the whole primary side of the substation sees the same rise in voltage and arresters at the transformer can protect the whole station. Switching surge energy dissipated by the arrester on systems with voltage greater than 240 kV can at times be significant and challenge the arresters’ energy handling capability.

Switching Surges Created Within Substations

Switching surges are also generated within the station from the operation of breakers or other switching devices. For both external and internal switching surges, the point on the AC wave where the device operates has a profound effect on surge amplitude. For example, when switched at peak voltage, a surge of 2 to 3 times initial voltage can be generated. In some cases, a breaker may pre-strike or restrike during operation. For internally generated surges, the surge wave-front can be very fast rising and will pose a serious threat to nearby insulation. For this type of switching surge, special mitigation with surge capacitors and arresters may be necessary. If a capacitor bank is switched within a substation, a significant surge can be generated that will need arrester mitigation.

Types of Substations & Special Protection Considerations

Transmission Substations

There are several different types of transmission substations, e.g. those with and without transformers, combination transmission and distribution stations, those that have large voltage control equipment such as series capacitor banks, etc. In all cases, arresters are applied to mitigate lightning and switching surges that may occur. In stations equipped only with breakers but no transformers, arresters may or may not be installed. For example, they may not be necessary if there are no possible significant end points or open points. Moreover, if line impedance remains unchanged, arresters are not required.

In transmission stations where there is either a step-up or step-down transformer, arresters should be used on both high side and low side of the transformer if surges can enter from either direction. If breakers are present, line entrance arresters should be considered for protection if the breaker is open at any time. At critical substations with breakers, if these are used to clear faults, it is possible that during such a fault-clearing event a second surge can impinge on the line side bushing while the breaker is in the open state. Now, the arrester at the transformer cannot protect the bushing and voltage doubling can occur with subsequent bushing flashover. To protect the breaker’s line side bushing, an arrester should be installed at the line entrance.

Distribution Substations

A distribution substation is one that steps a transmission voltage down to 34.5 kV or less and has outgoing feeders to urban, industrial, or commercial areas. Such substations can become quite complicated, with many types of equipment that need protection. The line side of the power transformer, for example, should always be protected. However if the low side cannot see a surge, arresters on that side are not necessary. The exception to this rule occurs when a breaker is located on the low side. In this case, it is recommended that arresters be installed between the sensitive windings and the potentially hazardous fast surge that a breaker can create.

At distribution feeder exits where lightning surges can enter the station, arresters should always be applied to mitigate these surges that will invariably arrive sooner or later. If these arresters are close enough to the LV side of the power transformer, they can also be used as protection for the transformer.

Another condition that often arises in distribution stations is the use of neutral grounding resistors (NGR) to limit the fault current into the system. When NGRs are used, arrester Uc and MCOV ratings need to be increased to account for the potentially long and high amplitude overvoltages that occur.

Indoor Air-Insulated Substations

Enclosed substations can vary from just a few components to an entire building full of electrical equipment. Industrial complexes, for example, often house numerous internal stations and should be treated the same as any outdoor air-insulated substation. A problem that can arise with this type of station is visibility of the arresters that are often buried within a cabinet, making easy access to them difficult. This only becomes a concern should there become a need to verify the arrester’s health using an infrared camera or by other means. It is therefore suggested that arrester enclosures have at least one side that is not fully enclosed and allows arresters to be evaluated if the need arises. Another issue that arises in this type of station more often than in other types, is long cable runs with open points. Voltage doubling issues arise in this configuration and arresters at the open points should be considered.

Full & Partial GIS Substations

A totally GIS station with GIS arresters is quite different from other substations and surge protection here is often specifically engineered. Arrester rating is often quite high in voltage to handle significant energy during any surge. If a station is partially air-insulated and exposed to lightning, surge protection is clearly necessary. But if the station is partially air-insulated yet inside a building, surge protection becomes of lesser concern. When all inputs and outputs are underground, surge protection design studies should be carried out to determine if and where to install arresters.

Generator Stations

Generator stations are the most difficult to protect because generator withstand voltage for very fast front surges is actually lower than the BIL. If a station is a small unit where incoming lines are only a few hundred meters from the generator, special protection is necessary. Not only can surges get through the step-up transformer, they can be generated at low voltages (e.g. 15 kV) by the breakers in the system. Very fast rising surges and high energy surges can be found on the generator bus. This is the place where surge capacitors are as important as surge arresters.

Types of Arresters Used in Substations

Station Class

The latest issue of IEC 60099-4 now refers to previous Class 2,3 and 4 arresters as ‘station class’ arresters, classified according to their test parameters. These usually have lower residual voltage as well as highest fault current withstand and energy handling ratings. While such arresters are used at nearly every substation, they may not always be the only type used. The primary reason to use station class arresters at substations lies in their fault current withstand capability. Since fault current in a substation often comes from several directions, available fault current can easily reach above the 20 kA limit of distribution arresters. The default arrester is therefore station class.

Distribution Class

The distribution class arrester, formerly referred to as Class 1 arrester, can be used in substations where fault current is below 20 kA. Here, the residual voltage of the distribution class arrester can often satisfy the station’s performance requirements. Moreover, for stations below 260 kV, the energy handling capability of a distribution arrester is typically also adequate. Before assuming that a station class arrester must always be specified, it is best to consider whether a more versatile, lower cost distribution arrester is actually sufficient.

Arrester Selection Considerations

MCOV U_c

There are no special considerations needed when selecting the Uc of an arrester in a substation. If the arrester is intended for protection of transformer windings, this should be as low as possible to offer the best protection.

Energy Rating

If an arrester is applied to lines with system voltages at 345 kV or above, energy ratings should be evaluated. If system voltage is below 345 kV, energy rating is not an issue, except when there is a large capacitor bank on the system.

Fault Current Withstand Rating

This arrester rating is especially important in substation protection since, as stated earlier, high fault current may be available. If so, arrester selection must take this into account.

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When planning to perform LLW on or in the vicinity of insulators, it is necessary to first determine their existing electrical withstand level. Evaluation of insulator damage that could affect electrical performance is limited to determining if condition of the insulators is safe for the duration of the work period for that day only and not intended to determine electrical end of life of the insulator.

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The edited contribution to INMR by Edward Niedospial, Technical Specialist at MacLean Power Systems offers his insight into how to specify the best materials and how to identify critical details, terminologies and performance criteria that might exceed what is offered in the standards. It also describes the basic composition of a polymer insulator, reviewing the components and various options along with how these options can impact long-term performance.

Pingxiang Huaci Insulators Group Co. Ltd.

China

PPC Insulators

Austria

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1) composite insulators (made of various elements or components);
2) polymer insulators;
3) non-ceramic insulators (NCIs);
4) synthetic insulators;
5) rubber insulators.

Yet, no matter what they are called, one aspect of a polymer insulator that is consistent across all suppliers is the basic composition, i.e.: core, housing and end connections. While this is true at a generic level, greater insight is needed in order to better understand how polymer insulators are manufactured and how those differences can impact performance.

Composition of Polymer Insulator

1) Core: The fiberglass core rod is the ‘heart’ of the polymer insulator and serves as both primary mechanical and electrical component.
2) Housing: Typically a generic term for the sheath and weather sheds, mostly made of either silicone or EPDM rubber and sometimes a combination of both.
3) End Connection: The end fittings, whether ductile iron or steel, are connected to the core rod and act as the mechanical connections through which system loads are applied through the core rod to the tower. Each insulator will typically have a line end fitting (LEF) and a tower end fitting (TEF).

Mechanical Performance

The core rod combined with the two end fittings make up the mechanical element of a polymer insulator. An insulator is first and foremost a mechanical device, holding the conductor in space and maintaining minimum phase clearances as required by the applied voltage.

Tensile Applications
• Suspension & Dead-end Insulators.
• Small OD Core Rods [Transmission Class – 16 mm, 22-24 mm, 32 mm, 38 mm and above]
• End fitting geometry governed by Standards (most of the connection ends).
• SML = Specified Mechanical Load = Rated Ultimate load.
• RTL = Rated Tensile Load = Working Load [standards define as 50% of SML but can vary by customer specification / definition for RTL ratings).
• Strength Rating not impacted by length of insulator.

Cantilever Applications
• Line Post & Braced Post Insulators.
• Larger OD Core Rods [Transmission Class = 2.5 in (63 mm), 3.0 in (76 mm), 3.5 in (88 mm) and above].
• End Fitting geometry somewhat defined by standards and typically requires some form of base connection to tower.
• Post applications can be horizontal, vertical, underhung, and braced.
• SCL = Specified Cantilever Load = Ultimate Cantilever Load
• MDCL = Maximum Design Cantilever Load = Working Cantilever Load.
• Multi-Axis Combined Loading – Vertical + Transverse + Longitudinal.
• Post Applications require a Load Curve to define mechanical capacity.

Fact: As the post gets longer, it becomes weaker (less cantilever capacity).
Fact: In a braced post application, the most common breaking limitation is dictated by the hardware and end fittings, not the core rod diameter. Hence the need for engineered solutions and testing.

Electrical Performance

Once an insulator is mechanically stable, its second function is to provide the insulating properties required. While the fiberglass core is the primary insulating medium, only when it is fully enclosed within a rubber housing is it capable of performing the electrical functions of the application. The most common material used to protect the fiberglass core rod from moisture, contaminants and other environmental stress is silicone rubber.

This housing consists of a sheath and weathersheds, which can be applied as a single body, as jointed bodies or using a modular process whereby the sheds are added separately to the sheath. No matter how the rubber is applied, the key dimensions to focus on when designing and comparing different insulator designs are: Dry Arc Distance, Leakage (Creepage) Distance, Rubber (Insulating) Length, and Section / Connection Length.

Critical Dimensions Pertaining to Electrical Performance:

Dry Arc Distance

Sometimes referred to as the arcing distance or flashover distance, it measures the distance metal-to-metal, up to the first shed, across all sheds and then from the last shed back to the end fitting. In simple terms, it is the air gap across the length of the insulator.
• This will dictate the Dry Flashover & Withstand electrical values and CIFO (Critical Impulse) values;
• Wet Flashover & Withstand (performance of the insulator when wet and under continuous water application) are determined by dry arc distance but also impacted by leakage distance and shed profile;
• All values above are statistically derived by each manufacturer and based on testing in a laboratory environment. The FO and Withstand values are nominal values with a +/- range;
• Dry Arc Distance is a measurable dimension that is fixed and can be used to compare different designs.

Leakage Distance

Sometimes referred to as creepage distance, this is the distance across the surface of the housing (all sheds) from line end fitting to ground end fitting.
• Protects the insulator from the impact of contamination and harsh environment;
• Leakage is another dimension to compare different designs.

Section Length

Connection length is the distance from line to tower connection of the insulator.
• Subject to change based on type of end fittings used;
• While section length is critical, it is second to Dry Arc Distance when comparing electrical performance of different insulators.

Rubber Length

Also known as minimal insulating length, this is the distance of the rubber housing, from end fitting to end fitting along the X-axis.
• This dimension is determined by the manufacturing equipment. Once defined by a supplier, it is not likely to change;
• Rubber Length is a reference dimension and less critical to performance.

Fact: The best way to increase dry arc distance is to increase section length. Each added inch (25.4 mm) of section length increases dry arc distance by an inch (25.4 mm). A one for one relationship.

Fiberglass Core Rod

The fiberglass core rod is the primary mechanical as well as electrical component, making it the ‘heart of a polymer insulator’. The core rod is made up of thousands of individual glass fibers (also known as rovings) bonded together by an epoxy resin.

Fiberglass Core Composition

The fiberglass core rod is made up of resin-impregnated fiberglass. However, type of resin and fiberglass, along with percentage of glass versus resin, is not defined in the standards. Rather, these are left to the rod manufacturer to define. For example, the decision on what glass and resin to use could depend on intended mechanical and electrical performance of the rod. A smaller OD core rod is primarily used for tensile applications, whereas a larger OD rod is required to meet higher compression and cantilever mechanical loads.

Fiberglass “Fiber” Options

Both options meet or exceed the tests defined in ANSI and IEC Standards
1) E-Glass = Electrical Grade Fiberglass
• Primarily used today to manufacture line post core rods;
• Used on early generation polymer types (suspension);
• Susceptible to brittle fracture (on suspension applications).
2) Corrosion Resistant E-Glass (CR-E or ECR) = Boron Free Fiberglass
• Boron Oxide removed from composition of glass fibers;
• Designed to eliminate brittle fracture;
• Same manufacturing process as standard E-Glass;
• Mechanically & electrically equal to E-Glass.

Resin Options

All options will meet or exceed the tests defined in ANSI and IEC standards.
1) Epoxy Resin = high electrical insulation, mechanical strength and resistant to chemicals. But the finished rod is potentially more brittle, impacting the crimping process. It can also experience issues due to the high temperatures used during the next step in insulator manufacturing, i.e. application of rubber housing.
2) Polyester Resin = lower cost resin, but also less chemical resistant. This is better suited for marine applications.
3) Vinyl Ester / Epoxy Blend = combines the best features of polyester and epoxy resins. The combined material (hybrid) is stronger than polyesters and more heat resistant than epoxies, making it ideal both for application of rubber and crimping.

Fiberglass Core Rod: Make or Buy?

Some polymer insulator manufacturers make their own rods while others purchase them as finished goods from a 3rd party supplier. In most cases, even those suppliers that manufacture their own rod have a 3rd party supplier approved as back-up. It is good industry practice to have multiple approved suppliers in case of emergency or for expanded capacity needs.

Typical Range of Core Rod Diameter by Application
◊ Tension Application (Suspension Insulators)
• 16 mm – 38 mm core diameters are the most common sizes.
◊ Cantilever / Compression Application (Line Post Insulators)
• 1.5 – 3.5 in core diameters are the most common sizes;
• Hollow core tubes.

Comment: Manufacturing the fiberglass core rod is a messy process and therefore best performed in a plant separate from manufacture of the finished polymer insulator. Even those manufacturers that produce their own rods typically do so in a separate factory.

Evaluating Quality & Performance Pertaining to Core Rod

• What is performance of rod (self-manufactured or purchased externally) with respect to the standard tests?
• How is incoming (self-produced/3rd party) rod inspected and approved for production?
• Does the manufacturer have lot control? Are they able to trace rods all the way through production to the completed polymer insulator?
• Do they use “Boron Free” core rod for suspension applications?

Rubber Housing & Weather Sheds

The function of the rubber housing, in conjunction with weathersheds, is to protect the core rod from the impact of the environment (including salt, dirt, dust and moisture) where insulators are put into service. Historically, rubber housings have been made of different materials, e.g. silicone, EPDM, and alloy materials.

However, not all silicone rubber materials are the same. Rather, quality and performance of silicone material is based on formulation and on manufacturing process by which the rubber is vulcanized, i.e. transitioned from the raw to the cured state.

A. Silicone Formulation

Each supplier uses a proprietary silicone formulation as part of their insulator design and which is a mixture of insulating materials, compounded as required by that supplier.
Fact: Because a material is silicone does not guarantee quality and proven performance. Instead, this will vary from formulation to formulation. When asked, each supplier should be prepared to discuss this and have test documentation to verify that their formulation will meet user expectations.

Specific % of each component in the formulation is unique to each supplier and can vary in performance. Too much or too little of one component of the formulation could be the difference between satisfactory and poor performance.

Basic Components of Silicone Formulation

1. Base Material = Elastomer or pure silicone is the base polymer that is the backbone (Si-O) of the formulation, responsible for hydrophobic performance, i.e. hydrophobicity over the life of the insulator, rate of hydrophobicity recovery and ability to encapsulate contaminants);
2. ATH [Aluminum Tri-Hydrate] is the arcing resistance agent in the formulation intended to improve tracking and erosion properties;
3. Curing agent is the cross-linking catalyst that triggers the vulcanization process, which begins to cure the silicone into its finished state;
4. Colorants: Silicone is typically clear and grey coloring is added to the compound;
5. Processing aids / mold release agents: These help material flow in the mold and ensure good release properties;
6. Special Additives / Fillers: These are defined by each supplier.

B. Processing Type

There are different methods of vulcanizing/curing the raw rubber into the finished material.
◊ HTV = High Temperature Vulcanization = a process by which heat is applied to adhere the rubber material to the surface of the core rod and curing the rubber as it is applied.
1. Most used in the following manufacturing processes: injection molding, extrusion and compression molding;
2. HTV silicone is the most commonly used material & processing in the industry;
3. HTV silicone has the longest proven performance history (both in terms of laboratory testing and field experience).
◊ LSR = Liquid Silicone Rubber – is a two component system (A & B) used primarily for its ease of injection and filling the mold tooling.
1. A lesser used process for manufacturing polymer insulators;
2. Cases of performance deficiencies have been reported.
◊ RTV = Room Temperature Vulcanized Rubber
1. Cures at room temperature without added heat, as for HTV;
2. Applied similar to caulking;
3. While used as part of some sealing processes, it does not provide the long-term performance of HTV silicone.

LSR technology has been improving and is now more accepted in the industry. Still, HTV silicone technology is often regarded as the more conservative approach, simply because it has a longer history of proven performance. When evaluating LSR versus HTV, it is critical to consider which material will better provide expected long-term performance.

Evaluating Quality & Performance of Rubber Material

• Testing the rubber materials in standard tests required in the industry;
• Although formulation of the silicone material would likely be considered proprietary (i.e. secret), an insulator supplier should nonetheless be prepared to present what their material consists of and why that specific formulation is being offered;
• Does the supplier have test data and service history to support this formulation?
• How does the manufacturer inspect incoming materials? Is this certified by the sub-supplier?;
• How is each lot of material lot coded and can each lot be tracked through production?

Comment:
An electrical grade core rod with a silicone housing is an ‘insulator’.
An electrical grade core rod without a silicone housing is an ‘isolator’.

Guys strains & brackets with painted or veiled rods do not have the insulating protection of a silicone-coated design.

End Fittings

The metal components attached to the ends of a polymer insulator are the end fittings. Depending on strength rating of the insulator (SML), these could be made of either ductile iron or steel. The higher the SML, the more likely an end fitting is a form of steel, whether cast or forged. Both iron and steel are then finished with a galvanized coating to protect the metal from harsh environments, which might otherwise cause corrosion and rusting.

Like all other parts of a polymer insulator, not all end fittings are the same. Although the connection types of end fittings are common and mostly well defined in the standards, an end fitting barrel is fully defined by each supplier.

Connection Types [ANSI & IEC]
• Socket & Ball (Most defined set)
◊ ANSI 52-5 (30k), 52-8 (40k), 5-11 (50k)
◊ IEC 16 (120 kN), 20 (160 kN & 210 kN), 24 (300 kN), 28 (400 kN), 32 (500 kN)
• Y-Clevis / Ball (Most common in US)
• Oval Eye / Oval Eye
• Clevis / Tongue (Well defined set)
• Clevis / Clevis

The connection ends of fittings are mostly governed by standards and gauges, but some are better defined and more complete then others. For example, the most defined set of end fittings would be the socket and ball connections, which whether ANSI or IEC are fully defined by Go & No/go gauges. Second to the socket and ball would be the Clevis / Tongue or Clevis / Clevis set of end fittings, which are also well defined but used primarily for international applications. At times, these can have non-standard SML ratings, defined by the customer in their specification.
Fact: In the U.S., the most common set of end fittings used are Y-Clevis / Ball for suspension and Oval Eye / Ball or Oval Eye / Oval Eye for Dead-end application.

While the connection type of end fittings is more common and defined by standards, their remaining connection geometry (sometime referred to as the barrel) is typically 100% unique to each individual insulator manufacturer.

Aside from connection geometry, end fittings can have many differences:
1. End Fitting Length: The length of each end fittings is determined by connection geometry and design of the end fitting barrel. It is likely that barrel geometry for each end fitting will be the same for each strength class. But when combined with different connection types, end fitting length varies for each type;
2. End Fitting Barrel: Length and outside diameter (OD) of the barrel of the end fitting are driven by the crimp zone as well as the crimping technology used by each manufacturer. Geometry of the crimp zone fluctuates based on amount of material displacement required to attain any desired SML rating.
3. Crimp Zone: Area along the length of the end fitting with manufacturing clearances at both ends to allow for proper compression of the end fitting;
4. End Fitting Lip: This is the end of the barrel opposite the connection end and this is where designs can vary most. Some can have very small radii at the ends while other designs can have a greater mass of metal making up the lip or corona ball.
• The need for the corona ball or larger lip is to prevent exposure of the core should an arc terminate on the end fitting. In the event of arc termination, the corona ball would be able to withstand multiple impulses without breaching the end fitting triple interphase;
• The larger lip is called a corona ball because it is designed to act as a small OD corona ring, providing protection from E-field stresses at the triple interphase;
• Finally, the corona ball feature can be the mounting geometry for a corona ring.
5. Triple Interphase (Point): This is the area where the rod, rubber and end fitting meet and in most designs is also the insulator’s sealing mechanism.

Fact: End fitting length most impacts insulator section length. The customer can match a length and make the dry arc distance variable or they can use the dry arc distance (rubber length) that would then make section length variable. Ideally, this is covered in the specification’s ± tolerance range.

End Fitting Procurement

As for pultrusion of the core rod, it is unlikely that casting, forging and galvanizing processes will take place in the same factory where insulators are being assembled. Rater, end fittings are typically sourced, depending on supplier and location. For example, most insulator manufacturers in the U.S. source all transmission class end fittings from countries such as China, India, Mexico and Brazil.

Fact: The manufacturer of a polymer insulator should do their own investigation and approval of each potential end fitting supplier as part of their internal quality system. It is unlikely that any supplier will ‘cut corners’ on quality of end fittings given how critical these are to performance of any polymer insulator design.

Evaluating Quality & Performance Pertaining to End Fittings

• The polymer supplier should be prepared to present customers with a complete evaluation and quality documentation for each approved end fitting sub-supplier;
• The supplier should present how they design and use their end fittings as part of the polymer insulator, including how end fitting design may or may not impact corona ring design and application;
• As with all materials, country of origin should be marked on end fittings;
• Each supplier should have a defined lot control process with the ability to track these lot codes to the production of the finished insulator;
• Each supplier should be able to provide documentation on how the end fittings are qualified, which can include ultimate strength ratings (which may also be part of the crimping process).

Conclusions

The process of evaluating polymer insulator designs can prove challenging, especially given the range of various material options. Users are well advised to use governing standards to assist in determining which designs best meet their needs. But the standards are sometimes not sufficient. Customer should also have a robust and detailed specification defining performance criteria and knowing which materials to require and what dimensions to make critical. Understanding the various options for a polymer insulator design and how these can impact long-term service performance is vital in order to conduct an effective evaluation of each supplier.

Appendix A: Multi-Axis Combined Loading & Load Curve Definitions

Appendix B: Brittle Fracture

KERI High Power & High Voltage Laboratories

South Korea

Powertech Labs Inc.

Canada

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This edited past contribution to INMR by experts at TE Connectivity dealt with applications where wildlife impact with electrical networks.

DALEKOVOD OSO

Croatia

EB Rebosio SRL, A Gruppo Bonomi Company

Italy

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Every power provider has suffered periodic disruptions from unplanned outages of one type or other. These have traditionally been classified as Weather, Wildlife or Unknown, with limited knowledge of the proportions due to each. Now, with greater knowledge, such unplanned outages are better categorized as due to:

1. Wildlife (birds & animals)
2. Weather (storms, wind, lightning)
3. Vegetation (tree branches)
4. Human intervention (accidental or deliberate)
5. Unknown or not yet categorized

Problems created by wildlife at substations and on overhead lines typically fall into two main categories: bridging and wildlife guano pollution flashover. While the result, i.e. a system trip and possible arc flashover, may be the same, the way this occurs, and the best solution can differ case-by-case. So do the remedial products that can be applied to compromised equipment.

Bridging is where a bird or animal makes contact between phases or between phase and ground, leading to a short circuit. For example, large birds can easily cause problems across all distribution voltages at substations and on lines. Phase bridging usually results in the creature being electrocuted and how it falls will determine whether the auto-reclosing system operates successfully or not. Often the bird or animal will fall away and allow the auto-recloser to re-energize the circuit. Although this may not normally require investigation by emergency crews, it usually leaves unnoticed but tell-tale evidence of damage.

Although the circuit might operate normally, a series of such events can lead to progressive damage that becomes worse with each successive trip and that finally causes hardware failure, e.g. where each trip burns out a single strand of conductor eventually dropping the line. Moreover, if the dead creature falls between its points of contact and remains there, this will result in the circuit not being able to be re-energized until an emergency crew removes the fault source. At least, this type of event can be logged with some certainty of what happened. By contrast, when the bird or animal falls to the ground or on top of a transformer, it is likely to be removed by a predator and no evidence will remain.

Most bridging problems occur on MV systems (typically <36 kV) designed such that bare conductors, bushings, busbar systems and other equipment have ‘air-spaced’ clearances that operate without issue under normal conditions. Clearances are typically up to 40 cm at substations and about 1m for overhead lines to allow for swinging conductors. Unfortunately, these clearances mean that a wide range of birds and animals can cause problems at substations and on lines. It should be noted that, although line conductors are generally 1 m apart, the most common failure mode is between the cross-arm (usually grounded) and the conductor – a typical clearance of only 30 to 40 cm.

Medium and large birds perch on a cross-arm and bridging usually occurs during landing or take-off. In more unusual cases, depending on location, wildlife such as bears, possums or even snakes climb poles and cause similar problems.

Pollution flashover from bird guano is a less frequent occurrence but can be every bit as damaging as bridging-induced outages. It is mostly associated with line insulators but can also occur at substations and differs from bridging since it can happen across all voltages – even up to EHV. Such flashovers of bushings or insulators result from build-up of guano for weeks or months during dry conditions when there is no rain to wash it away. Birds often favour certain places to perch, and this is often the extremity of a lattice tower arm, directly above the insulator string. While the build-up of guano can be considerable, so long as conditions are hot and dry the relatively small individual amounts of liquid guano dry quickly and surface resistance is not greatly altered.

Flashovers take place when mist, fog or rain returns, changing the dried guano into a semi-liquid state and greatly reducing surface resistance of the porcelain or glass insulator. If the build-up is sufficient to alter the conductivity of the insulator string, flashover can result. It should also be noted that another bird related failure mechanism – guano streamers –can cause flashover when a bird perched above an energized conductor emits a liquid streamer up to 2 m that effectively shorts out the otherwise safe air gap.

While all countries see some level of wildlife induced disruptions, the diverse nature of the birds or animals causing the problem as well as the different types of equipment and service conditions mean that the optimal approach to prevention also differs on a case-by-case basis. Once a failure mechanism is recognized, the latest generation of materials and designs make it largely preventable, often for the entire remaining life of the equipment.

Diverse Problems Across the Globe

The range of wildlife problems experienced by substation and overhead line engineers is too vast to cover in one article so common examples discussed below give a flavour of the diverse issues that can be encountered. Wildlife problems affecting power networks are categorized as ‘migratory related’, ‘local specific’, ‘food-related’ (predator or prey), ‘shelter/security/nesting related’, ‘seasonal’ and ‘other’.

Migratory issues relate only to birds passing through one area en route to some destination to feed and rest. These short time periods can cause local havoc by overcrowding mast tops where there is limited perch space available. In such cases, there is high risk of bridging phase-to-ground or phase-to-phase clearances. Other incidents include birds flying into lines near feeding sites, usually at distribution voltages where conductor clearances are such that large birds colliding with them can bring two conductors together, resulting in flashover. Once birds have completed their migration, they tend to return to the same location year after year. This means that, even if old nests are removed once the birds have left, they will be rebuilt the following year on that precise pole or tower.

The exact nature of any failure will depend on the design of affected equipment, type of bird involved, system voltage etc. but can be as simple as bridging while the bird is perching on a MV cross-arm. Guano induced failures most often impact HV suspension towers. Similar problems can arise from materials falling out of nests or when groups of birds fly in and around jumpers where there is a switch or pole top transformer.

Absolute data regarding the number of birds killed worldwide from interaction with power networks is usually under-reported since many countries do not record such statistics or fear their publication due to possible regulatory consequences. However, a figure measured in tens of millions of birds killed each year seems beyond question.

Seen from the viewpoint of electricity suppliers, this massive loss of wildlife equates to annual losses of over US$10 bln from lost revenues, damaged equipment, emergency call-outs by line crews and fines imposed by regulatory authorities. Some countries use legislation to protect endangered wildlife with severe penalties of up to US$ 500K.

Problems at substations are almost exclusively of a bridging nature when birds or animals bridge phases or phase-to-ground. Issues are generally not migratory related but can be seasonal, e.g. during cold weather when cats and similar size creatures are attracted to warmth close to a transformer. This seasonal problem can also be due to small birds building nests that attract a range of predators such as cats, snakes, larger birds or other species.

At MV substations, the ‘rule of thumb’ is that anything up to a maximum of 40 cm between phases or phase-to- ground is considered vulnerable to bridging by wildlife. This critical distance can be a greater (even up to 1 m) if a substation is plagued by wildlife such as snakes, monkeys and large birds of prey.

Solutions to Prevent Wildlife Outages

Given the huge financial costs, loss of wildlife and inconvenience to the public, it is a surprising that almost all the problems due to direct bird or animal interaction with power networks were preventable. The best solution to such problems is generally one that allows whatever wildlife is involved to safely access their chosen sites without causing electrical breakdown of any part of the system. It is equally important that any solution be cost effective such that the costs of installation are considerably less than the cost of the possible outages to be avoided.

It is still not possible to put a cost to avoiding every potential wildlife problem because of the diversity of issues and creatures. Still, it is estimated that it can vary from as little as US$1K to more than US$ 1mln. An average of circa US$10K is used in the U.S., where most data originates.

The importance of the protective material used cannot be overestimated. This is because any solution to a wildlife problem must not cause issues downstream because of material failure. On ‘day one’ almost any solution will perform to some degree; but the most effective solution will continue to work maintenance-free for the life of the equipment on which it is installed.

This will often mean at least 20 years or longer in challenging environments such as extremes of hot and cold, severe weather, long-term exposure to UV as well as a variety of pollutants, especially uric acid (the main chemical in bird guano). With these environments in mind, materials need to exhibit a minimum of technical criteria according to the relevant international standards, as shown below:

In addition to optimized geometry, materials used must deliver consistent performance, without electrical or mechanical breakdown, for over 30 years. As such, these materials must be robust mechanically, maintain excellent electrical properties while remaining tolerant to wildlife exposure. The images below illustrate what can happen in a short time when minimum levels of such performance are not met.

A variety of alternatives have been tried over the past years, including sonic deterrents, barriers, covers, electrified fences, smooth climbing barriers, chemical barriers and spined perching devices designed to drive the bird or animal away from a specific location. However, in most cases, the problems only re-surface elsewhere. There is also the consideration that migratory birds and even some resident animals always return to the same nest or feeding sites. This reinforces the importance of finding a solution to protect the reliability of electricity supply while also allowing wildlife unhindered access.

Many of the wildlife protective solutions adopted over the years have brought some limited, short-term or localized benefits. But experience has shown that the most successful overall solution is based on a range of electrically high performing polymeric materials, custom-designed for specific applications. Critical material performance factors include excellent long-term resistance to premature ageing, whereby the material is expected to maintain its electrical and physical properties, thermal endurance (continuous operating at up to 105°C) and high UV stability over some 30 years of service.

In parallel with outstanding material performance is good design. The key to successfully preventing bridging or guano flashovers lies in understanding the problem. This means identifying the most vulnerable bare metal places that need insulating. The solution will vary depending on the precise nature of any problem (e.g. a cat bridging phase-to-ground on a MV breaker or a white stork perching atop a cross-arm and making contact with one or more phases). As such, the local substation or line engineer is key to collecting this information along with looking for tell-tale signs of past wildlife interactions, as discussed earlier.

Vulnerable bare metal components can easily be insulated with either heat shrink or cold applied materials (or some combination of both) and typically up to 30 cm further along the busbar or overhead line than the farthest location of the known fault. This, however, is only general guidance and local knowledge should always be taken into account when available. In situations where there is bridging between phase and ground it is most common to protect both the equipment and wildlife by insulating the live side, e.g. busbar or conductor. It is also perfectly acceptable to insulate the ground side instead.

Long-Term Solutions

The following are examples of insulating vulnerable bare lines and substation equipment metalwork that had previously suffered multiple flashovers or were deemed at high risk of such events. In all cases, applying wildlife protective insulating materials effectively eliminated the problem while also allowing the wildlife to continue access.

Case 1: A white stork has a +2 m long wingspan. Thousands of these birds migrate each year from Africa to nest in Spain as well as central and south-eastern Europe. The nest is so big (up to 400 kg in weight and 2m in diameter) its presence will eventually cause flashover from accidental bridging between nest debris and conductor when conditions are wet or when birds bring conductive material (e.g. wire) to the nest Moreover, young birds that stray around the nest risk contacting the conductor. Insulating the bare metal fittings with a wraparound cover and the conductor with wraparound sleeving approx. 1.5 m from the nest in both directions offers both the bird and the power system long-term security.

Case 2: This crow’s nest in South Africa is precariously positioned on a 66 kV line between insulator and pole. The bird’s wingspan is sufficient to cause accidental bridging during landing or take off. Without the combination of conductor sleeve and wrap around connection cover, this bird/nest combination would at some point lead to flashover. The nest itself, while dry conditions last, might not cause problem. However once conditions become wet (rain, mist, fog, etc.) it is likely to short out enough of the insulator to cause flashover. Even in dry conditions, once the young birds are grown enough to move about, it is inevitable they will trigger a flashover.

Case 3: Laws in Germany require power utilities to implement countermeasures to prevent electrocution of birds and to protect both migratory and domestic species. The solution has been to use protective devices on 10/20 kV distribution mast tops. Insulation covers with an overall length of approximately 1.4 m prevent contact between birds and live conductors. There are many designs that can be attached using cable ties or live with insulated poles (hot-sticks). It is also possible to use transparent materials that allow aerial line inspection in terrain difficult to access. This solution may become more widely used as utilities increasingly introduce drones for maintenance.

Case 4: This insulator string demonstrates how the entire length can become heavily polluted with bird guano. The other photo shows that shielding the string makes it possible to keep the surfaces clean enough to never suffer pollution flashover due to wildlife. Here, it is critical that the material and design of the shield give many years of maintenance free service. This requires it be made of a high-performance UV stable polymer and robustly secured at the top of the string. After seasonal rains, accumulated guano will wash away and fall harmlessly away from the string below. In those countries with extreme dry conditions and where it might rain heavily only once in several years, it is even more important to use a material that is also resistant to attack by the uric acid in the guano.

Case 5: A substation in Croatia had all its bare live metalwork insulated, and heat shrink tubing on busbars. Connection points have cold applied wrap-around covers that can be removed for maintenance or inspection and then re-applied. The problem behind this installation was the phase-to-ground clearance on the MV side of the transformer and bus network where the typical 40 cm air gaps were being bridged by cats, crows & pigeons.

Case 6: An ageing MV substation in central Athens suffered from entry by cats and pigeons. With numerous phase-to-ground clearances well below the nominal 40 cm, it therefore experienced multiple flashovers. The solution was to cover all vulnerable bare metalwork with a range of high-performance polymeric covers, wrap-around sleeves and circular barriers that prevent cats climbing over the insulator and simultaneously touching the MV and ground sides.

Case 7:A MV substation in South Africa was built in an area of cleared scrub and trees inhabited by a troop of large monkeys. In its first year of operation it suffered 12 flashovers caused by monkeys that considered this their territory. The solution was to insulate all live bare metalwork across the site with a combination of heat shrink tubes and wraparound covers. Fully understanding the situation was critical to success on this site since phase clearances in some parts were approximately 1m which, if not for the monkeys, would not require additional insulation.

Case 8: A 20 kV substation in rural Germany was insulated against climbing animals such as martens and cats. Wraparound covers were cut on site to accommodate any unusual geometry, including the centre cover where a cut-out was added to allow access for an earth clamp in a relatively safe position. Covers that need such cutting in the field benefit from being made of a polymeric cross-linked material that will not propagate splits if cut roughly.

TECNALIA Electrical Labs

Spain

KERI High Power & High Voltage Laboratories

South Korea

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Conclusions

Awareness of the cost of wildlife-induced outages is growing and, with this, has come an increasing demand for reliable and robust solutions to protect both utility assets and the wildlife causing problems. Every power utility therefore has to contend with wildlife in the design and protection of its network. In finding the best long-term solutions, engineers must balance the need for exclusion/prevention and some tolerance of the wildlife in question.

The main causes of wildlife problems vary by region but the implications and basic design principles deployed are often the same. In addition to reliability enhancement and asset protection, an unacceptably high number of birds and other creatures are killed yearly due to electrocution. Legislation to protect many species is increasing, with countries such as the U.S. and Germany leading the way. Wider EU legislation regarding protection of birds is now being planned.

As with any network component, the material chosen as a solution must not break down and cause a reliability problem of its own during the life of the system. It is critical to specify high performing materials that are similar to those used on other overhead line components, including insulators and surge arresters. Most wildlife induced outages are now largely preventable.

The post Protecting Overhead Lines & Substations from Wildlife Induced Outages appeared first on .

Steady-state sheath voltages are kept within limits by proper selection of cable section lengths, grounding the sheaths at strategic locations and applying sheath cross bonding for field cancellation. If sheath grounding or application of SVLs are performed improperly, the SVL and the cable itself are at greater risk of damage.

This edited past contribution to INMR by experts at Power Engineers in the United States provided basic information about proper SVL operation and focused on consequences to SVLs in the event of failure to ground the cable sheath.

DALEKOVOD OSO

Croatia

PFISTERER

Germany

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Listen to Online Lecture on Sheath Voltage Limiter Failure from Improper Bonding of Cable Sheaths by Jon Leman

Sheath Induced Voltages

It is important to first understand the fundamentals of induced voltages on cable sheaths and Fig. 1 shows a simplified cable cross-section. While actual cables include additional layers, these prominent layers are sufficient for the purpose of this discussion. Any voltage on the sheath contributes to voltage difference between core and sheath and between sheath and ground. Typically, the insulation provided by the jacket is the controlling factor for maximum allowable sheath voltage. Typical jacket materials have a breakdown voltage in the range of 20-100 kV/mm. If the jacket is compromised, this can lead to further deterioration and cable failure.

Fig. 2 is a representation of a horizontal cable arrangement but with insulating components not shown. Each core conductor is surrounded by a concentric sheath, which is grounded at one end. From Faraday’s Law and Lenz’s Law, AC current flowing in the core induces a longitudinal voltage in the conductor sheath. Since one end of the sheath is grounded, the induced voltage appears between sheath and ground at the open end.

Distance between phases is often relatively small in the case of cable installations. Therefore, currents in adjacent phases and other nearby circuits should be considered when calculating the voltage induced in any sheath. If the phase currents are balanced (i.e. same magnitude with phase angles 120° apart), field cancellation effects can help reduce severity of induced voltage. Single-phase installations that do not benefit from field cancellation could see higher induced sheath voltages for the same core current.

IEEE Standard 575 and references cited at the end of this discussion provide methods for calculating sheath-induced voltages. Simulation can also be used but care must be taken to properly model return currents and electromagnetic coupling between sheaths, phase conductors and ground conductors. Table 1 offers an example showing results calculated using equations from IEEE 575 and verified with simulation using ATP-EMTP. A 230 kV XLPE insulated cable is arranged horizontally with 0.25 m spacing (0.8 ft). Section length is 305 m (1000 ft) and the sheaths are grounded at one end. Jacket thickness is 3.8 mm (0.15 in) and load and reported fault currents have a frequency of 60 Hz. Note that none of the induced voltages approach breakdown strength of the jacket (i.e. approx. 76 kV = 3.8 mm x 20 kV/mm).

Transients such as those from switching or lightning have higher frequency content and couple more effectively through cable capacitance. This can cause much higher voltage difference between sheath and external ground. Indirect lightning strikes to ground can also increase ground potential, causing a large transient voltage to appear across the jacket.

A simple ATP-EMTP simulation illustrates the impact of switching transients. A surge type source with 10 µsec rise time, 350 µsec tail time and amplitude of 2.0 per unit on 230 kV was applied to the core of one phase of the 230 kV XLPE cable described above. Transient voltage on the sheath of the same phase reached a peak value just above 110 kV while sheaths on adjacent phases saw peak transient voltages of about 80 kV. Depending on material and thickness of the jacket, these voltages could be high enough to result in puncture.

Basics of SVLs

More detail is available in Refs #6, 7, 8 & 9. A typical insulation coordination approach using SVLs to protect a cable jacket consists of the following:

1. Maximum continuous operating voltage (MCOV) of the SVL must be selected so that it will not conduct current for any sheath voltages induced by the maximum normal or emergency steady state load currents or fault currents flowing in core conductors;

2. The SVL is selected with a volt-current (V-I) characteristic that results in conduction for high voltages induced from transient events, such as switching and lightning. Since insulating properties of the jacket are not well defined and not assured by industry standards, ample protective margins are recommended;

3. The SVL must have an energy absorption capability sufficient for possible events that could result in SVL conduction. Total energy ratings and temporary overvoltage curves provided by manufacturers should be consulted.

SVLs are applied at locations corresponding to sheath-to-ground voltage peaks. This includes the open end of single point bonded cable sections or at section terminations where the sheaths of cross-bonded cable configurations are transposed (see Fig. 3).

Rigorous coverage of insulation coordination analysis for SVLs is beyond the scope of this paper and additional information about specification of SVLs is found in the literature. Fig. 4 shows the characteristics of an SVL selected for the 230 kV XLPE cable installation example. Applying this SVL and simulating the switching transient described above results in clamping of sheath voltages to about 11 kV (down from 110 kV). Transient SVL current peaks at about 5500 Amps and SVL energy absorption is approx. 615 Joules.

Impact of Ungrounded Sheath

Fig. 5 offers a circuit representation of one phase of a single point bonded system. One end of the sheath is connected directly to ground and an SVL is connected between sheath and ground at the other end. The capacitor circuit elements represent the sum of the distributed capacitance between core and sheath and sheath and ground. So long as one end of the sheath is grounded, sheath-to-ground capacitance has negligible effect. Steady-state induced sheath voltages in this case are due primarily to magnetic fields from core currents which couple to the sheath (i.e. mutual inductance, not shown).

If connection to ground is broken or not installed, electrostatic effects dominate and voltage at the sheath will be determined by a voltage divider using the respective capacitances. If resulting sheath voltage is higher than the SVL’s V-I curve, the SVL will conduct. Returning to the 230 kV cable discussed above, assume cables are direct-buried in conductive ground (i.e. ground potential reference at the surface of the cable jacket). Capacitance per unit length between concentric cylindrical conductors can be calculated using equation (1). Table 2 lists input data and results of the voltage divider calculation, overlooking presence of the SVL.

where:

ε₀ is the permittivity of free space;
ε_r is the relative permittivity of the dielectric;
r_s is the inner radius of the outer conductor; and
r_c is the inner radius of the inner conductor.

Comparing sheath voltage result to the V-I curve in Fig. 4, it can be seen that voltage is high enough to cause the SVL to conduct. However, the steady-state current cannot be found directly from the SVL’s V-I characteristic because it is limited by core-to-sheath capacitance. Manufacturer data typically does not include V-I characteristics for currents below 500 Amps. If nominal voltage of the cable system is much larger than the lowest published voltage of the V-I characteristic curve, current through the SVL can be approximated by assuming all the voltage drop is across the core-to-sheath capacitance. The larger the voltage across the SVL with respect to nominal system voltage, the more this approach will tend to overestimate SVL current. In this case, current will be limited to:

Even though this current is low, the heating effects are substantial and can result in rapid deterioration and failure of the SVL. (This will be explored below). An error that is occasionally made in conjunction with failure to ground the sheath is to install SVLs at both ends of the sheath. The result is similar but the current in each SVL will be approximately half the total capacitive current. The example above is for a direct-bury cable in which the reference ground surrounds the jacket. This configuration was selected for simplicity in calculating sheath-to-ground capacitance. But what about other cable configurations? Figs. 6 and 7 compare results of electrostatic finite element analysis for three cable configurations. .

In each case, distance between sheath and ground plane is successively larger and such larger distances result in reduction in capacitance between sheath and ground. The corresponding increase in capacitive reactance between sheath and ground causes an increase in sheath potential due to the voltage divider. Note that these are steady-state voltages the sheath would see without an SVL connecting it to ground. In all three cases, the example SVL would conduct. The further the sheath is from reference ground, the higher will be the floating potential. However, current in the SVL will be approximately the same in all three cases since it is the core-to-sheath capacitive reactance that limits the flow.

Thermal Impact of Induced Current

Estimated SVL current in an ungrounded sheath, as discussed above, was 2.47 Amps rms (about 3.5 Amps peak). In reality, this current will be a distorted waveform since the SVL only conducts for a portion of each cycle. Fig. 8 shows a simulated result of SVL currents for each phase of the 230 kV case installation having ungrounded sheaths. The simulation uses the SVL’s V-I characteristic from Fig. 4. The program estimates the V-I characteristic for operating points outside those specified by manufacturer data. Variations and asymmetry in current waveforms are due to the non-linear V-I characteristic and series capacitance as well as from variation in induced sheath voltages caused by asymmetry inherent in the horizontal cable arrangement (A to B spacing = B to C spacing ≠ A to C spacing).

Fig. 9 plots power absorbed by the SVLs. Peak power is about 26.5 kW and average power is about 13.3 kW. This level of power dissipation would cause rapid heating and failure of the SVL given that a typical SVL has a maximum operating temperature of 60°C (140°F). If temperature is too high, properties of the zinc oxide blocks change and a thermal runaway condition can occur.

To estimate current required to reach maximum operating temperature, a thermal finite element analysis was prepared for a representative SVL (see Fig. 10 which lists the thermal characteristics of the model). The zinc oxide block was set as a variable volumetric heat source with heat loss through conduction and radiation at the housing-to-air interface. The SVL model was placed in a region about the size of a link box enclosure. Boundaries of the link box region were set to a constant temperature of 10°C (50°F).

The simulation iterates until equilibrium is reached between heat sourced by the ZnO blocks and heat flow out of the SVL. Maximum temperature in the SVL was then recorded. This was performed for a range of ZnO heat generation levels. Post processing calculations determined conduction currents that would produce the ZnO heat energy assuming a 5 kV residual voltage across the SVL and assuming the instantaneous power is about twice the average power. Fig. 11 provides results of the analysis. These values are only an approximation but nonetheless demonstrate that even little steady-state current is sufficient to push an SVL to its thermal rating.

SVL currents in the milliamp range are possible for distribution level circuits with short section lengths. Under these circumstances, the SVLs could operate for some time before failing and would be sensitive to ambient temperatures and other thermal conditions.

Conclusions

Sheath voltage limiters are important in order to reduce cable losses and to protect cable jackets from lightning and switching transients but their use requires that the sheath be properly grounded. Failure to ground the sheath results in a floating potential condition. If the steady-state sheath voltage exceeds the V-I characteristics of the SVL, the unit will begin to conduct continuous current, limited by cable core-to-sheath capacitance. If an ungrounded condition exists on a transmission cable sheath, SVL currents can be in the range of a few Amps. This corresponds to an instantaneous power in the range of tens of kW and SVL failure will then likely occur quickly. The process leading to failure can take longer on short distribution circuits where capacitive currents might be in the milliamp range. Analysis of ungrounded conditions is not necessary for proper specification of SVLs. However, the conceptual analysis and calculations completed above are for training purposes and also provide information to help troubleshoot SVL failures.

References

[1] Lapp Tannehill, “Insulation/Jacket Materials: Physical Properties Chart,” [Online]. Available: https://www.lapptannehill.com/resources/technical-information/insulation-jacket-materials-physical-properties-chart. [Accessed 16 September 2019].
[2] IEEE Power and Energy Society, “IEEE Std 575-2014, IEEE Guide for Bonding Shields and Sheaths of Single-Conductor Power Cables Rated 5 kV through 500 kV,” IEEE, New York, NY, 2014.
[3] C. Adamson, E. Taha and L. Wedepohl, “Determination of the Open-Circuit Shath Voltages of Cable Systems,” IEEE Proceedings, vol. 115, no. 8, 1968.
[4] M. Shaban, M. A. Salam, M. A. B. Sidik, Z. Buntant and W. Voon, “Assessing Induced Sheath Voltage in Multi-Circuit Cables: Revising the Methodology,” in IEEE Conference on Energy Conversion (CENCON), Johor Bahru, Malaysia, 2015.
[5] V. K. Gouramanis, G. C. Kaloudas, T. A. Papadopoulos, K. G. Papagiannis and K. Stasinos, “Sheath Voltage Calculations in Long Medium Voltage Cables,” in IEEE PowerTech, Trondheim, 2011.
[6] J. Woodworth, “Sheath Voltage Limiters Protect HV Power Cables,” Zimmar Holdings Ltd./INMR, 9 February 2019. [Online]. Available: https://www.inmr.com/sheath-voltage-limiters-protect-power-cables/. [Accessed 18 September 2019].
[7] D. Cao, X. Liu and X. Deng, “The Suitability Analyses of Sheath Voltage Limiters for HV Power Cable Transmission Lines,” in 2nd International Conference on Electrical Materials and Power Equipment, Guangzhou, China, 2019.
[8] A. Heiss, G. Balzer, O. Schmitt and B. Richter, “Surge Arresters for Cable Sheath Preventing Power Loss in MV Networks,” in 16th International Conference and Exhibition on Electricity Distribution, IET, Amsterdam, Netherlands, 2001.
[9] Insulect, “Sheath Voltage Limiters,” 2019. [Online]. Available: https://insulect.com/products/sheath-voltage-limiters-svl. [Accessed 17 September 2019].
[10] C. R. Paul, Analysis of Multiconductor Transmission Lines, Second Edition, Hoboken, NJ: John Wiley & Sons, 2008.
[11] J. He, R. Zeng, S. Chen and Y. Tu, “Thermal Characteristics of High Voltage Whole-Solid-Insulated Polymeric ZnO Surge Arrester,” IEEE Transactions on Power Delivery, vol. 18, no. 4, 2003.
[12] S. B. Lee, S. J. Lee and B. H. Lee, “Analysis of Thermal and Electrical Properties of ZnO Arrester Block,” Current Applied Physics, vol. 10, no. 1, pp. 176-180, 2010.

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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.”

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The key function of a phase spacer is to prevent the approach of phase conductors on a high voltage overhead circuit due to formation of ice sleeves and the presence of strong wind. Such natural events can lead to deflection of conductors that are subjected to the increased mechanical loads being generated. In the case of ice sleeve formation, different possible outcomes can arise. For example, an ice sleeve deposited on the lower phase can disperse while that deposited on the upper phase remains. Any whiplash oscillation triggered on the lower phase can then bring it dangerously close to the upper phase still fitted with the ice sleeve and generate discharge between the phases due to jumping. Similarly, during heavy ice storms where wind blows sideways to a line, rotational movements can occur that cause permanent deformation of the conductor as well as significantly increased load on both line insulators and the towers themselves. In the most serious cases, this can even lead to collapse of structures supporting the line. This presentation explains how proper engineering and application of phase spacers in these types of situations can counteract excessive rotational forces on phase conductors and help avoid these types of issues.

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Understanding & Mitigating Corona on Polymer Insulators
by Jeff Butler

Many factors must be understood to ensure the expected long-term performance of today’s utility assets and one of these is impact of electric field on components that make up transmission hardware and insulator assemblies. Specifically, it is important to understand the possible effects of corona on polymeric type insulators.

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