What Is Keraunic Level?

Keraunic level is defined as the average annual number of thunderstorm days or hours for a given locality. A daily keraunic level is called a thunderstorm-day and is the average number of days per year on which thunder will be heard during a 24-h period.

By this definition, it makes no difference how many times thunder is heard during a 24-h period. In other words, if thunder is heard on any one day more than one time, the day is still classified as one thunder-day (or thunderstorm day).

The average annual keraunic level for locations in the U.S. can be determined by referring to isokeraunic maps on which lines of equal keraunic level are plotted on a map of the country.

What Is Ground Flash Density?

Ground flash density (GFD) is defined as the average number of strokes per unit area per unit time at a particular location. It is usually assumed that the GFD to earth, a substation, or a transmission or distribution line is roughly proportional to the keraunic level at the locality. If thunderstorm days are to be used as a basis, it is suggested that the following equation be used (Anderson, 1987):

Nk = 0.12Td


Nm = 0.31Td

Nk is the number of flashes to earth per square kilometer per year

Nm is the number of flashes to earth per square mile per year

Td is the average annual keraunic level, thunderstorm days

Lightning Detection Networks
A new technology is now being deployed in Canada and the U.S. that promises to provide more accurate information about ground flash density and lightning stroke characteristics. Mapping of lightning flashes to the earth has been in progress for over a decade in Europe, Africa, Australia, and Asia.

Now a network of direction-finding receiving stations has been installed across Canada and the U.S. By means of triangulation among the stations, and with computer processing of signals, it is possible to pinpoint the location of each lightning discharge.

Hundreds of millions of strokes have been detected and plotted to date. Ground flash density maps have already been prepared from this data, but with the variability in frequency and paths taken by thunderstorms from year to year, it will take a number of years to develop data that is statistically significant. Some electric utilities are, however, taking advantage of this technology to detect the approach of thunderstorms and to plot the location of strikes on their system. This information is very useful for dispatching crews to trouble spots and can result in shorter outages that result from lightning strikes.


Substation design involves more than installing apparatus, protective devices, and equipment. The significant monetary investment and required reliable continuous operation of the facility requires detailed attention to preventing surges (transients) from entering the substation facility.

These surges can be switching surges, lightning surges on connected transmission lines, or direct strokes to the substation facility. The origin and mechanics of these surges, including lightning, are discussed in detail in Chapter 10 of The Electric Power Engineering Handbook (CRC Press, 2001).

This article focuses on the design process for providing effective shielding (that which permits lightning strokes no greater than those of critical amplitude [less design margin] to reach phase conductors [IEEE Std. 998-1996]) against direct lightning stroke in substations.

The Design Problem
The engineer who seeks to design a direct stroke shielding system for a substation or facility must contend with several elusive factors inherent in lightning phenomena, namely:

• The unpredictable, probabilistic nature of lightning
• The lack of data due to the infrequency of lightning strokes in substations
• The complexity and economics involved in analyzing a system in detail

There is no known method of providing 100% shielding short of enclosing the equipment in a solid metallic enclosure. The uncertainty, complexity, and cost of performing a detailed analysis of a shielding system has historically resulted in simple rules of thumb being utilized in the design of lower voltage facilities. Extra high voltage (EHV) facilities, with their critical and more costly equipment components, usually justify a more sophisticated study to establish the risk vs. cost benefit.

Because of the above factors, it is suggested that a four-step approach be utilized in the design of a protection system:

1. Evaluate the importance and value of the facility being protected.

2. Investigate the severity and frequency of thunderstorms in the area of the substation facility and the exposure of the substation.

3. Select an appropriate design method consistent with the above evaluation and then lay out an appropriate system of protection.

4. Evaluate the effectiveness and cost of the resulting design.


Surge arresters may be of the valve or expulsion type. They are rated not only on their normal voltage classification in kV, but also on their crest voltage capability in kV at a standard 1.5 × 40-μs wave (or other specified wave), and their discharge-current capability in amperes or thousands of amperes (kA).

For high-voltage application, surge arresters may consist of a number of unit-value valve arresters connected in series in one overall unit, as shown in below for a 69-kV arrester.

Cross section of a 69-kV Thyrite (valve) surge arrester.

Lightning or surge arrester elements are enclosed in an insulated casing. Under severe operating conditions, or as a result of multiple operations, the pressure generated within the casing may rise to the point where pressure relief ratings are exceeded.

The arrester then may fail, with or without external flashover, exploding and violently expelling fragments of the casing as well as the internal components, causing possible injury to personnel and damage to surrounding structures. The action represents a race between pressures building up within the casing and an arcing or flashover outside the casing.

The ‘length’ of the casing of the arrester limits its ability to vent safely. The use of polymer insulation for the casing permits puncturing to occur, without the fragmentation that may accompany breakdown and failure of porcelain.


What Is A Helmholtz Coil?

A Helmholtz coil, in its usual, basic configuration, consists of two similar concentrated coils of small winding cross section compared to coil radius, arranged on a single axis, at a spacing of one coil radius along their common centerline.

If electric current is passed through the coils, a very uniform magnetic field is produced in the space between them.

If a Helmholtz coil is connected as a sensor to a fluxmeter, then if a bar, plate, or arc magnet is placed in the center with the magnetic axis parallel to the coil axis, and the magnet is then removed (or rotated 180°), the resultant output of the fluxmeter can be shown to be proportional to the magnetic moment of the magnet.

The magnetic moment may be defined either as the product of the magnetic flux through the magnet\ times the pole spacing of the magnet, or as the average axial flux density of the magnet times the magnet volume:

M = φ I2 = Bav Vm (2.62)

where M = magnetic moment
φ = flux through the magnet
Iρ = pole spacing within the magnet
Bav = average flux density in the axial direction, in the magnet
Vm = magnet geometric volume

The combination of a fluxmeter and a Helmholtz coil becomes an accurate, fast, and easy way to determine the strength of a magnet with one measurement.

Although originally intended for use with bar or plate magnets, the method can also be used with arc segments (which are used in some permanent-magnet motor rotors).


As a gaussmeter measures the magnetic flux density nearly at a point, a flux meter measures the total magnetic flux across an area (that is, the integral of flux density over an area or, for constant flux density, the flux density times the area).

It is more accurate, however, to say that what is measured is not flux, but the change of flux. According to Faraday’s law of induction,

E = N dφ/dt

Where E = voltage across a coil of n turns
φ = iTEGRALB dA = flux (2.60)
B = magnetic flux density
A = area
N = number of turns on the coil linked by flux φ
Integrating this equation,

φ = (1/N) iNTEGRAL (E dt + φ0)

Where φ0 is an arbitrary constant of integration, normally set to zero to begin the measurement.

That is to say, it is possible to measure an amount of flux passing through an object such as a magnet by placing the object to be measured in a tight-fitting coil, then removing the object, while integrating the voltage across the coil with time.

This is the principle of the fluxmeter. Alternately, it is possible to remove the object, rotate it end for end 180°, and reinsert it into the coil. In this case the change of flux is twice that through the object.

The sensor for a fluxmeter is just a coil of wire, usually made at the time by the operator. The wire may usually be of small diameter, because very little current flows during the measurement.

The larger the number of turns, the larger the signal. However, if the coil resistance becomes relatively\ high (possibly 50 Ω or more), some flux meters with relatively low input resistance may require a correction.


This plastic sheet (usually, but not always, green) is often used to inspect magnetic parts, especially for the transitions between magnetic poles (north-south transitioning to south-north, etc.). Unfortunately, a lack of understanding of the way the sheet is constructed often leads to misinterpretation of the results.

Microscopic flakes of nickel are first coated with an oil, in which a plastic material has been dissolved. The plastic then separates out, forming a skin around the oil drop. The flake is then free to rotate within the shell of plastic, which is invisibly small in diameter.

Many layers of these spheres (perhaps 30) are deposited onto a plastic sheet, which forms a support. The support sheet may be on the order of 0.005 in thick, and the layers of spheres may add on the order of 0.002 in to the total thickness.

When no magnetic field is present, the flakes lie flat in the bottom of their spheres, reflecting upward the color of the plastic sheet. When a magnetic field is present in the plane of the sheet, the brightness is intensified.

On the other hand, if a magnetic field is present which is normal to the sheet—that is, at approximately right angles into or out of the sheet—the flakes stand on end, aligning with the field. When this occurs, the light reflected off them bounces back and forth until it is absorbed, in a manner similar to the light in a metal tube, and no light is reflected (it is black).

It can be seen, then, that the green color means either that no field is present, or that there is a field, in the plane of the sheet. For example, a region in which flux is leaving the sheet at 45° from left to right as it rises will appear to be black when viewed from the right side.

The same region viewed from the left side, however, will appear to be green! In order to have a consistent result from the indications of this material, it must be viewed from directly overhead, not from an angle.

The nickel flakes saturate at a relatively small field. This observer noted a change in color at about 10 G and full transition to black at about 100 G for one type of sheet.

The transition width for two neodymium-iron magnets side by side in air may be from on the order of +4000 G to −4000 G, but the part of this transition which is indicated by the plastic sheet is much narrower—on the order of 1⁄40 as wide.

Based on the indications of the plastic sheet, some have thought they were seeing a very narrow transition between magnet poles, to a degree which is physically impossible.


What Is Gaussmeter?

In 1896, Edwin Herbert Hall discovered in the process of working on his doctoral thesis that if electrical current was passed through a thin strip of gold while it was exposed to a magnetic field, a small but measurable voltage was developed across this strip at right angles to both the direction of current and field, proportional to both.

This effect results from the Lorentz force on moving electrons in a magnetic field, which forces them to one side of the strip. They build up a charge there until the charge is just sufficient to counter the effect of the magnetic field.

These devices are known today as Hall-effect sensors. They are made of semiconductor material, not for the amplifying effects used in transistors, but merely because such materials have a high electrical resistance.

The higher resistance forces the electrons in the current stream to move at a higher speed, which increases the resulting voltage. A Hall sensor measures magnetic field strength in a very small region, nearly at a point (a typical sensor might have an active site on the order of 0.030 in across).

Only the part of the magnetic vector which is normal (that is, at right angles) to the Hall element is measured, so the sensor must be oriented in that direction. Most gaussmeters on the market today use Hall sensors.

A few, however, use some other principle, such as magnetoresistors, which change their resistance in a magnetic field; magnetoresonance, a method used in medical MRI scanners; and, for less accurate devices, mechanical gaussmeters, which use the attraction of two permeable materials for each other, against a spring, in the presence of a magnetic field.


All of the components in an electrical system are designed to operate at their rated voltages for optimum efficiency and long service. An ideal electrical system would provide constant voltage to all customers under all conditions of load.

Unfortunately, because of the unpredictable dynamics of a practical system, none is ideal. Thus, it is necessary to include voltage regulators in the system to correct its performance and keep its voltage reasonably close to an ideal constant.

There are now at least four different methods for maintaining close to ideal voltage on electric power transmission and distribution systems. These include the use of stepvoltage regulators, transformer load-tap changers, fixed and switched capacitors, and static var (volt-amperes reactive) systems (SVS).

However, single-phase step-voltage regulators are most frequently used to regulate voltage in electric power distribution systems.

There are many reasons, both technical and economic, why system voltage should be held close to its intended standard.

Among them is the fact that overvoltage shortens the life of heating elements in resistive appliances, components in electronic products, and filaments in both incandescent and fluorescent lamps.

Moreover, overvoltage can damage motor-driven appliances and tools.

On the other hand, undervoltage increases the time taken for the resistive elements of appliances to heat up while also causing motors to overheat and lose efficiency. It will also reduce the performance of electronic products such as computers, radios, and TVs, and dim the illumination from luminaires.


What Are Reclosers? What Is Its Purpose and How Recloser Works?

The increasing electrical loads on distribution lines caused by increasing demand, particularly in the suburbs, have caused utilities to raise their operating voltages. Voltages are now being distributed at 13.8, 23, and 34.5 kV and higher .

This higher voltage has led to the formation of smaller service regions or more sectionalizing to\ minimize the impact of an electrical outage in parts of each region. Ironically, the probability of fault occurrence has increased as operating voltages have increased because of the combination of higher voltages and longer distribution lines.

These have made the lines more susceptible to outages on lower-voltage, shorter lines because of the higher probability of transformer bushing flashovers, falling tree limbs, lightning strikes, and other causes.

Early in the last century conventional disconnect switches met the requirements for sectionalizing, but this is no longer true. The switching capability of a disconnect, while marginal at 2.4 to 4.8 kV, is completely inadequate at 13.8 kV and higher.

To isolate a section of distribution line by opening a disconnect, the entire feeder must first be dropped, and this adds to the extent of the outage. Moreover, during emergency conditions the probability of the occurrence of a disconnect caused by operator error increases proportionally.

Many different kinds of switches are now available to meet a wide variety of applications economically. The single-pole switch and side-break switch are intended for pole-top installation on distribution feeders, while the vertical-break switch was designed for distribution substations or feeders.

These switches perform all of their switching duties without causing external arcing, and they also provide the reliable isolation of a visible air gap. A few examples of their versatility and use are the following.

# During emergency situations requiring fast response, a modern interrupter switch can drop the load without complicated circuit breaker and switch sequencing.
# There is no need to drop individual loads because the switch can drop the entire load.
# Lines can be extended and additional load accommodated (within the rating of the switch) without affecting switching ability.
# A loaded circuit can be dropped inadvertently (through an error or misunderstanding) with no hazard to the operator or to the system.
# Interlocking is not required between the primary switch and the secondary breaker in transformer operation.

Because of the no-external-arc feature of most modern interrupter switches, phase conductor spacing can be much less than that established for the older horn-gap switch. On the secondary side of the substation there are more feeders and more heavily loaded and longer transmission lines.



All high-voltage circuit breakers have

# Contacts that operate at system voltage
# Insulation between main contacts and ground potential (porcelain, oil, or gas)
# Operating and supervisory devices
# Insulated links between the operating devices and the main contacts

Most power circuit breakers are opened and closed automatically by remote control. Various kinds of operating mechanisms are used. Among them are AC or DC solenoids, compressed air, high-pressure oil, springs, or electric motors.


High-voltage circuit breakers are rated by maximum voltage, insulation, maximum continuous and momentary current-carrying capacity, maximum interrupting capacity, transient recovery voltage, interrupting time, and trip delay.

Circuit interruption occurs when a plasma arc with temperatures exceeding 20,000 K appears for a short time interval between the main contacts. This occurs when the current passes zero, and it is determined by the time relationship between the buildup of dielectric strength of the gap between the open contacts and the rise of transient recovery voltage.

The interrupting capacity of a circuit breaker, measured in kilovolt-amperes (kVA), is the product of the phase-to-ground voltage in kilovolts (kV) of the circuit and the interrupting ability, in amperes (A), at stated intervals and for a specific number of operations. The current is the root-mean-square (rms) value existing during the first half-cycle of arc between contacts during the opening stroke.


The five general types of high-voltage circuit breakers are as follows.

1 Oil circuit breakers use standard transformer oil, an effective medium for quenching the arc and providing an open break after current has dropped to zero. There are two general types of oil circuit breakers: dead-tank for the higher voltage ranges and live-tank for lower voltages.

Oil circuit breakers have been improved by adding such features as oil-tight joints, vents, and separate chambers to prevent the escape of oil. Also, improved operating mechanisms prevent gas pressure from reclosing the contacts, making them reliable for system voltages up to 362 kV.

However, above 230 kV, oil-less breakers are more economical.

2 Air-blast circuit breakers were developed as alternatives to oil circuit breakers as voltages increased. They depend on the good insulating and arc-quenching properties of dry and clean compressed air injected into the contact region.

3 Magnetic-air circuit breakers use a combination of strong magnetic field with a special arc chute to lengthen the arc until the system voltage is unable to maintain the arc any longer. They are used principally in power distribution systems.

4 Gas circuit breakers take advantage of the excellent arc-quenching and insulating properties of sulfur hexafluoride (SF6) gas. These outdoor breakers can interrupt system voltages up to 800 kV.

These circuit breakers are typically included in gas insulated substations (GISs) that offer space-saving and environmental advantages over conventional outdoor substations. Gas (SF6) circuit breakers are made with ratings up to 800 kV and continuous cur rent up to 4000 A.

They are alternatives to oil and vacuum breakers for metal-clad and metal-enclosed switchgear up to 38 kV.

5 Vacuum circuit breakers, more accurately termed vacuum-bottle interrupters, are generally used for voltages up to 38 kV and continuous current ratings to 3000 A. They are used for higher system voltage, current, and interrupting ratings, and are typically specified for metal-clad and metal-enclosed switchgear in distribution systems.


The logic behind calling 1000 V to 72.5 kV a medium-voltage range is not obvious unless it is compared with the maximum North American grid voltages of 800 kV and more common transmission system voltages of 60 to 500 kV.

Nevertheless, medium-voltage circuit breakers can protect AC generators, some transmission and subtransmission lines, and distribution substations.

The industry classifies circuit breakers in the following way:
# Medium-voltage power (1000 V to 72.5 kV)
# Low-voltage power (1000 V and below)
# Industrial molded case (600 V and below)
# Miniature or branch circuit (240 V and below)

All circuit breakers are electromechanical devices that make and break currents under normal conditions and make, carry for a specified time, and break currents under abnormal conditions such as short circuits. Circuit breakers, like transformers and batteries, are made in a wide range of ratings.

Because the higher-voltage circuit breaker contacts can be damaged or destroyed by the burning action of electric arcs when the contacts of a high-voltage circuit are opened, various methods have been developed to provide an appropriate quenching medium around the contacts that will assist in extinguishing any arcs formed as rapidly as possible.

The names of mediums used for extinguishing the arc are included in the descriptions of the circuit breaker. For example, there are oil circuit breakers, air-blast circuit breakers, and magnetic-air circuit breakers.

The selection of the appropriate method for quenching the arcs depends on the cost-effectiveness and availability of sources of and means for providing air blasts, insulating gas, insulating oil, magnetic fields, or vacuums.

The two basic designs for high-voltage circuit breakers are oil and oil-less. The oil type circuit breaker had been the most popular for outdoor service up to 362 kV, but the air-blast and gas-type versions have been gaining in popularity.

At 550 and 800 Kv, oil-less breakers predominate. For new indoor applications magnetic-air and vacuum circuit breakers predominate, along with some gas-type. Indoor magnetic-air, air-blast, and vacuum breakers have been adapted for outdoor use in the 2.5- to 34.5-kV range by protecting them with metal covers.

It is essential that the correct circuit breakers, fuses, and switches be selected for each power control application because of their importance in the design and function of the overall electrical system.

Immediately upon sensing a short circuit or break in the supply line, fuses and circuit breakers must isolate the sections of the electrical network where the fault occurred, to prevent further damage while permitting the remainder of the network to remain operational.


The design of the high-voltage substation must include consideration for the safe operation and maintenance of the equipment. Switching equipment is used to provide isolation, no load switching, load switching, and/or interruption of fault currents.

The magnitude and duration of the load and fault currents will be significant in the selection of the equipment used. System operations and maintenance must also be considered when equipment is selected.

One significant choice is the decision of single-phase or three-phase operation. High-voltage power systems are generally operated as a three-phase system, and the imbalance that will occur when operating equipment in a single-phase mode must be considered.

Metal-enclosed low-voltage power circuit breaker switchgear indicates a design which contains low voltage ac or dc power circuit breakers in individual grounded metal compartments. The circuit breakers can be either stationary or draw out; manually or electrically operated; fused or unfused; and
either 3-pole, 2-pole or single-pole, construction.

The switchgear may also contain associated control, instruments, metering, protective and regulating equipment as necessary. Definitions, ratings, design and production tests, construction requirements, and guidelines for application, handling, storage, and installation are covered in IEEE C37.20.11.

Low-voltage metal-enclosed switchgear is typically installed in industrial plants, utility and cogeneration facilities, and commercial buildings for the protection and distribution of power for loads such as lighting, machinery, motor control centers, elevators, air conditioning, blowers, compressors, fans, pumps, and motors.

Low-voltage switchgear is available in ac ratings up to 635 V and 5000 A continuous and in dc ratings up to 3200 V and 12000 A continuous. Short-circuit current ratings are available up to 200 kA.


What Is An SF6 Power Circuit Breaker?

SF6 gas has proven to be an excellent arc quenching and insulating medium for circuit breakers. SF6 is a very stable compound, inert up to about 500 degrees C, non-flammable, non-toxic, odorless, and colorless. At a temperature of about 2000K SF6 has a very high specific heat, and high thermal conductivity, which promotes cooling of the arc plasma just before and at current zero, and thus facilitates quenching of the arc.

The electronegativity behavior of the SF6, that is, the property of capturing free electrons and forming negative ions, results in high dielectric strength and also promotes rapid dielectric recovery of the arc channel after arc quenching. SF6 breakers are available for all voltages up to 1100 kV, continuous currents up to 5000 A for conventional breakers (higher for generator breakers), and shortcircuit interruption up to 80 kA.

SF6 breakers of the indoor type have been incorporated into metal-clad switchgear. Outdoor designs include both dead tank and live tank circuit breakers.

Over the years, SF6 circuit breakers have reached a high degree of reliability; thus they can cope with all known switching phenomena. Their closed-gas system eliminates external exhaust during switching operations and thus perfectly adapts to environmental requirements. Their compact design considerably reduces space requirements and building and installation costs.

In addition, SF6 circuit breakers require very little maintenance. All ratings are economically satisfied by the modular design. Each pole is equipped with one or more interrupters; stored energy, spring, hydraulic, or pneumatic driving mechanisms are provided for each pole or 3-pole unit.

Gas-density monitors are standard. In the closed position, the current flows over the continuous current contacts and the complete volume of the breaker pole is under the same pressure of SF6 gas.

The precompression of the SF6 gas commences with the opening operation. The continuous current contacts separate and the current is transferred to the arcing contacts. At the instant of separation of the arcing contacts, the pressure required to extinguish the arc is reached.

The arc produced is drawn and at the same time exposed to the gas, which escapes through the ring shaped space between the extinction nozzle and the moving arcing contact. The escaping gas has the effect of a double blast in both axial directions.

Until the open position is reached, SF6 gas flows out of the puffer cylinder. The existing overpressure maintains stability of the dielectric strength until the full value of the open contacts at the rated service pressure is reached.

In the case of high-current interruption, arc energy heats the gas, resulting in a pressure rise in the static volume (heating volume) V1. This pressure then quenches the arc at an ensuing current zero. In the low-current case an auxiliary puffer (volume, V2) generates sufficient pressure for interruption.

Necessary force requirements for the mechanical system are therefore drastically reduced. All ancillary equipments, including the oil pump and accumulator associated with the drive, form a modular assembly that is mounted directly on the circuit breaker, thus eliminating installation of piping on the site. The metal-enclosed GIS breaker is provided with the necessary items to fit into the substation arrangement.

The main equipment flanges of the breaker are fitted with contact assemblies to accept the isolator moving contacts. Other equipment modules can be coupled to the same flanges. On the fixed-contact end of the circuit breaker, provision is made for coupling two modules, facilitating the mounting of an extension module to connect the second busbar isolator.

Dead tank SF6 breakers typically employ gas-filled bushings. Such bushings are usually integral to the circuit breaker itself and are not interchangeable with other apparatus bushings.

Electrical grading is provided by a lower throat shield. Ring-type bushing current transformers are located at the base of the bushing. Potential taps are not generally available in SF6 bushings because of the lack of a capacitive grading structure.

Porcelain alternatives, such as composites, have been used to provide greater safety (explosion resistance), easier handling (lighter and nonbrittle), seismic performance (lighter and stronger), and pollution performance.


What Are Generator Circuit Breakers?

Generator circuit breakers represent another class rated for very high continuous currents and short circuit currents, typically at generator voltages. Generator breakers are incorporated into generator bus ducts and can include other switchgear components for measuring current, detecting faults, and grounding.

Generator breakers are available up to 50 kA nominal current and up to 220 kA interrupting current. Two technologies are employed—air blast at the higher ratings and SF6 self blast at the lower and medium power levels (up to 120 kA). For nominal currents above 20 kA, the generator breaker is usually equipped with a forced cooling system, using water, for example. Generator breakers have been available since the 1960s.

Advantages of using generator breakers include the following:
Reduced station cost by eliminating station transformers and increasing station layout flexibility.

Simplification of operation, especially during commissioning and recommissioning; this is because the generator can be handled as a separate unit, isolated from the main and unit transformers.

Fault protection between the generator and transformer. Two zones of protection are created and generator faults are cleared by the opening of the generator breaker alone.

Unbalanced load protection of the generator.

Protection of the generator from transformer faults.

Reliability/availability increase.

Historically, generator circuit breakers have been of air-blast design with pneumatic operators. This is the technology still used today for large nuclear and fossil fuel power plants (up to 1500 MW), and large pumped storage installations.

The design has a tubular housing and is horizontal. Newer designs utilize SF6 self-blast technology and hydraulic operators. These are rated for application to smaller power plants (gas turbine/cogen, for example) from 60 to 400 MW and smaller pumped storage installations.


Outline and interrupter details of a generator air-blast circuit breaker-type DR, 36 Kv, up to 50 kA with forced cooling, 200 kA.



To secure and protect substation equipment from damage due to a seismic event, the relationship between earthquakes and substation components must first be understood. Earthquakes occur when there is a sudden rupture along a preexisting geologic fault.

Shock waves that radiate from the fracture zone amplify, and depending on the geology, these waves will arrive at the surface as a complex set of multifrequency vibratory ground motions with horizontal and vertical components.

The response of structures and buildings to this ground motion depends on their construction, ductility, dynamic properties, and design. Lightly damped structures that have one or more natural modes of oscillation within the frequency band of the ground motion excitation can experience considerable movement, which can generate forces and deflections that the structures were not designed to accommodate.

Mechanisms that absorb energy in a structure in response to its motion can help in damping these forces. If two or more structures or pieces of equipment are linked, they will interact with one another, thus producing a modified response.

If they are either not linked, or linked in such a way that the two pieces can move independently — an ideal situation — then no forces are transferred between the two components. However, recent research has shown that even a well-designed link may contribute to the response of the equipment or structure during a seismic event.

For electrical reasons, most pieces of substation power equipment are interconnected and contain porcelain. Porcelain is a relatively brittle, low-strength, and low-damping material compared with steel. Furthermore, unless instructed to do otherwise, construction personnel will install conductors with little or no slack, which gives the installation a neat and clean look.

This practice does not allow for any freedom of movement between components. When the conductor is installed with little or no slack, even small differential motions of one piece of equipment can easily impact an adjacent piece of equipment.

This is because each piece of interconnected equipment has its own frequency response to an earthquake. While the equipment at one end of a tight conductor line is vibrating at 1 Hz, for example, the other piece of equipment at the other end of the conductor is “trying” to vibrate at, say, 10 Hz.

It is easy to see that when they vibrate toward each other, the line will go slack. When they vibrate away from each other, the line will suddenly snap tight, which will impact the equipment. This is a well-documented occurrence.

Usually, the larger, more massive equipment will pull the smaller, weaker equipment over. Substation equipment with natural frequencies within the range of earthquake ground motions are especially vulnerable to this type of damage by seismic events.


The hydrogen gas given off from batteries that are located in confined areas can, at certain concentrations, become an explosion hazard. Therefore, a continuously operating exhaust system should be installed when batteries are located in a room sized to contain only the battery(ies) or are located in a confined space where the buildup and retention of hydrogen gas could reach potentially explosive concentrations. 

The entrance door(s) to a battery room should have a "No Smoking" or "No Open Flame" warning sign posted on it. Lighting switches should be located outside of the room. All codes should be followed concerning the type of lighting fixtures, wiring, and installation of eye-wash stations. Precautions should also be taken to assure that the acid fumes will not be present in a concentration sufficient to cause damage to nearby relay contacts.

Surge arresters
Surge arresters should be properly sized and located to minimize the possibility of an equipment fire initiated from surges.

Direct-stroke lightning
If needed, direct-stroke lightning protection, e.g., grounded lightning masts, static wires, etc., should be installed so that all equipment and buildings are protected. Guidance in the installation of this protection can be found in ANSI/ NFPA 780-1992 [B30].

All equipment in the substation should be properly grounded with correctly sized grounding conductors and proper terminations to dissipate fault currents. This is necessary to prevent failure of the grounding conductor or termination, which could result in more severe equipment damage and an associated fire. Guidance in grounding equipment can be found in IEEE Std 80-1986 [B45].

Fault-sensing and interrupting devices
The proper relaying or fault-sensing devices in combination with an interrupting device should protect all circuits and equipment. The combination of the devices used should operate and isolate the fault before any further and more serious problems could occur.

Metal-clad switchgear
Consideration should be given to the installation of a fixed extinguishing system for the protection of metal-clad switchgear that contains oil-filled equipment. Consideration should be given to the installation of smoke detectors on the ceiling of the switchgear room above the switchgear lineups. For guidance, see FM Data Sheet 5-19 [B41].

Oil-filled reactors
Consideration should be given to the installation of a fixed extinguishing system for the protection of oil-filled reactors. If the reactor(s) is enclosed in a sound-reducing housing, the fixed fire-extinguishing system should be installed both inside and outside the housing.

Power capacitors
Power capacitor units located outdoors, which contain a combustible dielectric fluid, should be a minimum of 10 ft (3.0 m) from any building not of fire-resistive construction. Capacitor units located indoors, which contain a flammable dielectric fluid, should be separated from adjacent areas by a 1 h fire-rated barrier.

Diesel or gasoline engines
A substation may contain diesel-, propane-, or gasoline-powered engines for fire pumps or standby electrical power. Installation of these engines should conform to ANSI/NFPA 37-1994 [B19]. Electrical apparatus on engines and generators should be fully spark-protected. For design requirements for propane fuel use, see ANSI/NFPA 58-1995 [B20].

Fuel-handling systems
Substation fuel-handling systems should conform to ANSI/NFPA 30-1993 [B18]. Buried tanks and piping should be corrosion-protected, and loading points for fuel should be located at the perimeter of the substation. Underground tanks should be located in a clearly marked area and should not be subjected to vehicle loads.

Relay and control panels
Panels should be designed and constructed to meet the recommendations for flame retardance contained in IEEE Std 420-1982 [B48].

Gas-insulated components
Consideration should be given to the control of SF6 gas and the mitigation of gas by-products that may be generated as either a direct or indirect result of fire. Precautions regarding the harmful effects of SF6 gas and SF6 gas by-products are given in IEEE Std C37.122-1993 [B43] and IEEE Std C37.122.1-1993 [B44].

High-pressure oil-filled-cable pumping plants
Consideration should be given to the installation of a fixed extinguishing system for the protection of oil-filled-cable pumping plants and storage tanks.


Cranes or hoists having adequate lifting capacities should be available for handling material during installation. Nylon web slings provide an ideal means for lifting equipment without damaging it.

Gas is handled through commercially available gas-processing trailers that contain vacuum pumping equipment, gas storage tanks, compressors, filters, and dryers. The size of the individual gas compartments and the evacuating and storage capacity of the gas-handling equipment is especially important in large stations.

Suitable evacuating equipment and a heat source to counteract the chilling effect of the expanding gas may permit filling directly from gas cylinders or gas-handling equipment. High-voltage test equipment is required for checking the quality of the insulation after installation.

Adapters for high voltage testing may be required. These include a suitable entrance bushing for connecting the high voltage to the gas insulated conductor and a termination for closing off the end of the equipment when the entire assembly has not been completed. In many cases, it may be possible to use an entrance bushing that is a part of the installation.

When tools and alignment templates not readily available on the open market are required for installation and maintenance of the equipment, one set should be furnished, by the supplier, with the equipment when it is delivered.

The following materials should be on hand before the bus is opened:
a) Gas-processing equipment with adequate storage capacity
b) Electrolytic or electronic hygrometer or comparable equipment for measuring moisture levels
c) Insulating gas leak detector (Where double “O” rings are used, a manometer can sometimes be connected at the sensing hole to measure any increase in pressure between the “O” rings. Commercial high-viscosity, noncorrosive solutions may be used to locate larger leaks at a sensing hole, at welds, or at bolted flanges.)
d) Dry air
e) Clean plastic gloves and work uniforms
f) Lint-free cloths and manufacturer-recommended solvents
g) Temporary plastic bags or covers for sealing openings after components have been removed
h) Commercial-type vacuum cleaner with high efficiency particulate air (HEPA) filters and nonmetallic
i) Tools supplied and recommended by the manufacturer
j) Ventilating equipment
k) Handling and lifting equipment
l) Maintenance manual and erection drawings
m) Ladders and platforms as required


Live-tank SF6 gas puffer-type interrupters are utilized by most circuit switchers today. In the closed position, the contacts are surrounded by a flow guide and piston assembly which is ready to mechanically generate a “puff” of SF6 to cool and deionize the arc that is established prior to circuit interruption.

The moving cylinder attached to the contact assembly is driven by the main opening spring, causing the gas to be pressurized by the stationary piston. The stationary contact “follows” the moving contact as the piston assembly achieves the prepressurized gas condition.

When the contacts (which are hollow tubes) part, an arc is established and the gas flow divides into two parts and flows down the stationary and moving contact tubes. The alternating nature of the arc current waveform results in two current zeros every cycle. As long as the arc is sufficiently “hot” or conductive through the SF6 dielectric medium, the current will reestablish.

At the first current zero where the SF6 density is sufficient to stop the arc from reestablishing itself and to provide necessary dielectric strength, the arc is interrupted. This entire process from trip signal initiation to current interruption requires from 3 to 8 cycles or 50 to 133 ms in modern circuit switchers.

Figure above illustrates a typical “blade-disconnect model” circuit switcher with the interrupter and blade connected in series. For opening, the trip device, called a “shunt trip,” receives a trip signal when the relay system detects an abnormal condition within the specified range or when the operator desires a high-speed circuit opening. By discharging its operating spring, the shunt trip rotates the insulator above it at high speed, thus tripping and discharging the opening spring in the driver mechanism.

This actuates the interrupter to open the circuit. If the insulator above the shunt trip continues to rotate, by motor or manual actuation of the drive train controls, the blade opens to achieve visible isolation. The blade-hinge mechanism is actuated directly by the rotating insulator through the driver mechanism.

Continued rotation of the insulator after the blade is open will “toggle” the drive train controls to lock the blade in its open position. For closing, the reverse rotation of the insulator first releases drive train toggle and allows the blade to begin closing.

The shunt-trip units have already recharged during the opening operation. As the blade closes, the closing springs are charged in the driver. The last few degrees of closing rotation lock the blade in position and release the closing springs in the driver, thus closing the interrupter.

The opening springs are charged as the closing springs discharge. If the unit has closed into a circuit condition that provides a trip signal to the shunt trip units, the opening process may immediately proceed since all springs are charged and all controls are ready.

The closing operation may be achieved in other designs by closing the interrupter during the opening stroke of the blade. When a close operation is called for, all that is necessary is to close the blade, because the interrupter is already closed. Because of the arc established in air for this type of closing, high-speed operation of the blade is necessary to minimize damage to contacts and prevent flashovers.

Both methods of closing are proven over many years of field use. Bladeless circuit switchers operate exactly the same as blade models, except that on opening, the insulator rotation is used only for driver and interrupter actuation. Models that depend on high-speed blade operation for closing are available in bladeless nondisconnect configuration, but circuit closing must be accomplished by other means.

For models without shunt trip, opening is accomplished by rotating the insulator to the point where the driver opening spring would normally be tripped by the shunt trip’s rotation. This configuration is used where protection duty is not a function of the circuit switcher.


What Are Circuit Switchers?

Circuit switchers are mechanical switching devices suitable for frequent operation; not necessarily capable of high-speed reclosing; capable of making, carrying, and breaking currents under normal circuit conditions; capable of making, and carrying for a specified time, currents under specified abnormal conditions; and capable of breaking currents under certain other specified abnormal circuit conditions.

They may include an integral isolating device. Circuit switchers available today use SF6 as an interrupting medium and may be equipped with a trip device connected to a relay to open the circuit switcher automatically under specified abnormal conditions, such as overcurrent or faults.

A circuit switcher, like a circuit breaker, must carry normal load currents within a specified temperature range to prevent damage to key components such as contacts, linkage, terminals, and isolating device parts.

Principal designating parameters of a circuit switcher are maximum operating voltage, BIL, rated load current, interrupting current, whether an isolator is required, whether a trip device is required, and whether manual or motorized operation is required.

A circuit switcher essentially combines the functions of a circuit breaker (without reclosing capability) and a disconnecting switch (by providing visible isolation, but not necessarily meeting the safety requirements of all users).

A circuit switcher provides a cost-effective alternative means of transformer protection and switching, line and loop switching, capacitor or reactor switching, and load management, with protection in most instances.

Evolution of the circuit switcher concept provides a more in-depth understanding of its application versatility and its limitations.

History of Circuit-Switcher Development
After World War II, the drive to electrify the remaining rural and sparsely populated areas of the United States was renewed. Providing fully rated circuit breakers for switching loaded circuits was frequently beyond budget limitations. This created a need for new transmission and subtransmission voltage circuit-switching devices.

One such device could be described as a load interrupter. It appeared in a wide variety of forms. Most were attachments to disconnect switches.

Initially, most of these devices used low-volume oil as an interrupting medium. Ablative gas generating devices and later vacuum displaced oil. With rare exceptions, these devices had deficiencies. In the mid-1950s, SF6 was first employed as an interrupting medium. The application was an interrupter attachment for disconnect switches.

Whereas ablative devices and vacuum bottles are limited to approximately 30-kV recovery voltage per gap, this single-gap SF6 device was readily applied on 138-kV systems for up to 600 A load switching.

Most of these vacuum, ablative, and SF6 devices were shunted into the circuit during the disconnect switch opening process. As the 1960s approached, the circuit switcher was born. It appeared as an in line device. While the first version employed a number of ablative devices in series, it soon evolved into the use of SF6 as a medium.

Because of the unfavorable experience with the earlier devices, the general acceptance of the circuit switcher took much effort and considerable time. A typical installation is shown below.

Applications for circuit switchers have been primarily for transformer protection. The circuit switcher provides load-switching capability and mainly protection for faults that originate on the secondary side of the substation transformer.

The zone of protection for circuit switchers in this location is typically from the current transformers inside the transformer on the high-voltage bushings to the secondary feeder breakers. There is generally shorter strike distance on the secondary bus and more exposure to flashover from wildlife and other causes.

Therefore, circuit switchers are specifically tested to interrupt the higher transient recovery voltages (TRVs) associated with faults initiated on the secondary of the transformer and cleared by the high-side protective device. For application where the available high-side short-circuit current exceeds the device’s capability, blocking relays can be used. However, in most applications this is not necessary.


A key part of an automated feeder switching system is the automated switch. The term “automated” in this context means the switch is designed for use on an automated or SCADA system.

In order to be automated, existing switches may be retrofitted with motor operators, current and voltage sensors, RTUs and communication devices to allow the remote operation necessary to realize the benefits available with automated feeder switching systems.

However, switches designed for occasional, manual operation may not be entirely suitable for operation on an automated distribution circuit feeder. Manual switches are typically not designed to be operated the hundreds of times required by a fully automated system over the life of a typical switch.

Nor are they ordinarily designed for duty cycle fault-closing to allow the system operator to inadvertently close into a fault from the SCADA master station—and still leave the switch in an operable condition.

More recently, switches designed specifically for automation have appeared in the market like the one below.

Such switches incorporate design features that make them particularly applicable for use in an automated feeder switching system:

1. Duty-cycle fault-closing allows the switch to be closed into a typical fault several times before experiencing damage severe enough to render the switch inoperable.

2. Integrated voltage and current sensors provide the ability to monitor voltages, currents, and loads that are in turn used as inputs to algorithms to effect automated switching for fault isolation and restoration and for shifting loads for circuit optimization.

3. Integrated operating mechanisms enable the switches to be operated remotely via computer commands. Integration with the switch ensures optimum operation without the need for cumbersome ground-to-switch linkages.

4. Integrated load interrupters should be designed to allow operation under any weather conditions since it will not be possible to visibly inspect the switch for ice or other problems prior to operation.

5. Integrated control power sources eliminate the need to rely on locally available control power sources—or to install such power sources.

6. Integrated visible air-gap isolation provides the visible air gap when needed for certain types of line work.

In addition, an associated control package should include switch-operating controls, a local/remote switch, backup power for dead-line SCADA operation, a remote-terminal unit, and data communication devices. The entire package should be assembled and tested for proper operation by a single supplier to eliminate the need for the utility to perform the integration.

The control box should be separately located from the switch to allow access by technicians who are not qualified in high-voltage operations. In underground switchgear applications, the control should be isolated from the high-voltage compartments of the switchgear.


Electric substations produce electric and magnetic fields. In a substation, the strongest fields around the perimeter fence come from the transmission and distribution lines entering and leaving the substation.

The strength of fields from equipment inside the fence decreases rapidly with distance, reaching very low levels at relatively short distances beyond substation fences. In response to the public concerns with respect to EMF levels, whether perceived or real, and to governmental regulations, the substation designer may consider design measures to lower EMF levels or public exposure to fields while maintaining safe and reliable electric service.

Electric and Magnetic Field Sources in a Substation
Typical sources of electric and magnetic fields in substations include the following:
1. Transmission and distribution lines entering and exiting the substation
2. Buswork
3. Transformers
4. Air core reactors
5. Switchgear and cabling
6. Line traps
7. Circuit breakers
8. Ground grid
9. Capacitors
10. Battery chargers
11. Computers

Electric Fields
Electric fields are present whenever voltage exists on a conductor. Electric fields are not dependent on the current. The magnitude of the electric field is a function of the operating voltage and decreases with the square of the distance from the source. The strength of an electric field is measured in volts per meter.

The most common unit for this application is kilovolts per meter. The electric field can be easily shielded (the strength can be reduced) by any conducting surface such as trees, fences, walls, buildings, and most structures. In substations, the electric field is extremely variable due to the screening effect provided by the presence of the grounded steel structures used for electric bus and equipment support.

Although the level of the electric fields could reach magnitudes of approximately 13 kV/m in the immediate vicinity of high-voltage apparatus, such as near 500-kV circuit breakers, the level of the electric field decreases significantly toward the fence line. At the fence line, which is at least 6.4 m (21 ft) from the nearest live 500-kV conductor (see the NESC), the level of the electric field approaches zero kV/m. If the incoming or outgoing lines are underground, the level of the electric field at the point of crossing the fence is negligible.

Magnetic Fields
Magnetic fields are present whenever current flows in a conductor, and are not voltage dependent. The level of these fields also decreases with distance from the source but these fields are not easily shielded. Unlike electric fields, conducting materials such as the earth, or most metals, have little shielding effect on magnetic fields. Magnetic fields are measured in Webers per square meter (Tesla) or Maxwells per square centimeter (Gauss). One Gauss = 10^–4 Tesla. The most common unit for this application is milliGauss (10^–3 Gauss).

Various factors affect the levels of the fields, including the following:

1. Current magnitude
2. Phase spacing
3. Bus height
4. Phase configurations
5. Distance from the source
6. Phase unbalance (magnitude and angle)

Magnetic fields decrease with increasing distance (r) from the source. The rate is an inverse function and is dependent on the type of source. For point sources such as motors and reactors, the function is 1/ r^2; and for single-phase sources such as neutral or ground conductors the function is 1/r.

Besides distance, conductor spacing and phase balance have the largest effect on the magnetic field level because they control the rate at which the field changes. Magnetic fields can sometimes be shielded by specially engineered enclosures. The application of these shielding techniques in a power system environment is minimal because of the substantial costs involved and the difficulty of obtaining practical designs.


What Are Air Circuit Breakers And How Does Air Circuit Breaker Works?

The usual construction of an air circuit breaker makes use of two fixed terminals mounted one above and the other in a vertical plane, which, when the breaker is closed, are bridged under heavy pressure by a bridging member operated by a system of linkages.

Auxiliary and arcing contacts close before and open after the main contacts. The arcing contacts are easily renewable. The breaker is held closed by a latch which may be tripped electrically or mechanically.

Modern breakers are trip-free.

Many breakers use a solid bridging member with spring-mounted self-aligning contacts. The contact surfaces are made of silver so that oxidation will not cause excessive resistance and overheating.

Arcing contacts of modern breakers use a silver-tungsten or copper-tungsten alloy which is arcresistant. The secondary contacts, where used, are usually of copper or silver alloy.

Barriers between poles are generally furnished with breakers on ac and dc circuits 250 V and above, and special arc chutes, quenchers, or deionizing chambers are also used throughout the available lines of air circuit breakers.

These devices are made in different forms by different manufacturers and serve to improve the interrupting performance of the breaker and to shorten the arcing time.

Air-insulated high-voltage electrical equipment is generally covered by standards based on assumed ambient temperatures and altitudes. Ambient temperatures are generally rated over a range from –40°C to +40°C for equipment that is air insulated and dependent on ambient cooling.

At higher altitudes, air density decreases, hence the dielectric strength is also reduced and derating of the equipment is recommended. Operating (strike distances) clearances must be increased to compensate for the reduction in dielectric strength of the ambient air.

Also, current ratings generally decrease at higher elevations due to the decreased density of the ambient air, which is the cooling medium used for dissipation of the heat generated by the load losses associated with load current levels.


A Tutorials On The Operating Mechanism Of Power Circuit Breaker

Opening and closing of power circuit breakers under service conditions is seldom performed manually, since most breakers are installed in systems designed for remote control providing specific redundancy.

Various means of operation are used, such as
(1) dc solenoids,
(2) solenoids operated from an ac source through a dry-type rectifier,
(3) compressed air,
(4) high pressure oil,
(5) charged spring, and
(6) electric motor.

Automatic reclosing of breakers in overhead line feeders is frequently used to restore service quickly after a line trips out because of lighting or other transitory fault. Instantaneous or time-delay reclosing may be provided with a lockout to prevent more than one to several successive reclosures, as desired.

If the fault is cleared before the lockout feature operates, the reclosing device resets itself, permitting a complete cycle of reclosing at a subsequent fault.

The circuit-breaker-operating device has to cope with the increasing requirements in interrupting and current-carrying capability as well as with shorter operating times. Simplicity of design, robustness, and reliability have to ensure safe operation of this vital link between the electrical system controls and the interrupter.

The principle of a pneumatic drive is sketched for an extra high voltage circuit breaker which functions according to the differential piston principle in figure below.

A pneumatic interlocking device in connection with the SF6 gas system ensures that the breaker always remains in the defined open or closed position even on loss of air pressure. Besides opening and closing functions, effective damping of the highly accelerated moving parts is incorporated.

Principle of the drive system for an SF6 outdoor breaker: (a) closed position; (b) open position.


How Power Circuit Breaker Closing Operation Works?

Circuit breakers are designed to perform the closing and reclosing operations as per standard requirements. When operated to close on long lines, extra-high-voltage circuit breakers require special measures to keep switching overvoltages within specified limits.

Such measures may be single or multiple step closing resistors, synchronously closing at the moment of voltage zero, or polarity-controlled-closing, which means closing during the period of equal polarity at the line and source side of the breaker. When operated to close on capacitor banks special measures may be taken to limit transient currents and voltages.

Such measures may be closing resistors; controlled closing at the moment of voltage zero for grounded wye capacitor banks; or controlled closing on ungrounded wye capacitor banks where the first phase is closed at the moment of voltage zero and the other two phases are closed at a point where the voltage difference between the two phases is zero.

When operated to close on power transformers or shunt reactors special measures may be taken to limit inrush transient currents and transient voltages. Such measures may be single or multiple step closing resistors, or controlled closing at the moment of voltage peak.

The magnitude of overvoltages on energizing and reenergizing is influenced by the nature and variables of the power system. Parameters of supply side and line must be taken into account in order to compute the overvoltages or to determine them using transient network analyzers or transient analysis software, such as electromagnetic transients programs (EMTP), power systems computer aided designs (PSCAD), or alternative transient program. (ATP).

For a summary of the magnitude of overvoltages occurring when energizing high-voltage lines, based on numerous studies and measurements in high-voltage networks, see Table 10-9. Surge arresters may also be used to limit switching overvoltages.

Overvoltages Occurring When Energizing High-Voltage Lines


How Power Circuit Breaker Operation Works?

Reaction time and speed of modern breakers has increased to reach standard interrupting times of 2 to 5 cycles, with 2 to 3 cycles being common at high voltage. Interrupting time is measured from energizing of the trip coil until the extinguishing of the arc.

The interrupting time during close-open operations may exceed the rated imterrupting time by either 1/2 cycle (for 2 and 3 cycle breakers) or by 1 cycle (for 5 cycle breakers).

The current standard operating duty cycle consists of the following:
Open – T – Close – Open - 3 min – Close – Open

T is defined as either 15 s or 0.3 s depending on whether the circuit breaker is rated for high speed reclosing; this distinction is important in application.

Even circuit breakers rated for high speed reclosing must still be allowed a 0.3-s delay to allow for proper recovery of insulation following the initial fault interruption.

For existing oil and air-magnetic circuit breakers, the standard operating duty cycle was:

Open – 15s – Close - Open.

For additional operations, and/or any close operation in the duty cycle with a time delay of less than 15s after an opening operation, the interrupting rating and related required capabilities of the oil or air magnetic breaker have to be derated.

All operations within a 15-min period are considered part of the same duty cycle and a duty cycle shall have no more than five opening operations.

For guidance on interrupting capability for reclosing service for oil and air-magnetic breakers manufactured after 1960 refer to IEEE C37.0106. Circuit breakers manufactured prior to IEEE C37.7-196010 have different basis of rating.


Circuit breakers are built for voltage ratings as defined in IEEE C37.042 and IEEE C37.063. They have to be dimensioned to withstand the maximum voltages as specified. The rated maximum voltage is the upper limit for operation.

For circuit breakers rated in accordance with ANSI C37.06-19874 (or earlier), the range between upper and lower limit is defined by voltage range factor K. Current-interrupting capabilities vary within this range in inverse proportion to the operating voltage.

For circuit breakers rated in accordance with ANSI C37.06-19974 (or later), the current-interrupting capability is a constant Ka value at any voltage equal to or lower than the rated maximum voltage.

The insulation level is determined by the rated withstand test voltages specifying the low frequency voltage (kV, rms) and the impulse voltage (kV, crest). High-voltage breakers must essentially withstand switching surges and both full and chopped-wave lightning impulses.

For multiple-break circuit breakers, equal voltage distribution over the series breaks is achieved by grading capacitors paralleled to the interrupting chambers. Coordination between inner and outside insulation, as well as insulation coordination between interrupters and ground insulation, has to be properly designed to prevent flashover inside the breaker or over the open break.

Outdoor breakers are generally available with special bushings that provide increased creepage distance for installation sites with highly contaminated air. For heavily polluted atmospheres, spray washing of live or deenergized breakers may be an additional measure.

Because of the method of design with enclosed ground insulation, the GIS circuit breaker is not influenced by atmospheric pollution. For installation at altitudes above 3300 ft (1000 m), altitude correction factors have to be applied.

The values of rated maximum voltages and insulation levels are multiplied by these factors to obtain the values for the application. The altitude correction factors are as listed in ANSI/IEEE C37.04-1979.

Correction factors are under discussion in an IEEE Switchgear committee working group and are expected to change. These factors will be published in IEEE C37.100.15. Particular reference is made to the rating structures and preferred ratings for ac high-voltage circuit breakers per the latest standard revisions of IEEE C37.042 and IEEE C37.063.


GIS is assembled of standard equipment modules (circuit breaker, current transformers, voltage transformers, disconnect and ground switches, interconnecting bus, surge arresters, and connections to the rest of the electric power system) to match the electrical one-line diagram of the substation.

A cross section view of a 242-kV GIS shows the construction and typical dimensions (Figure 2.1). The modules are joined using bolted flanges with an “O” ring seal system for the enclosure and a sliding plug-in contact for the conductor.

Internal parts of the GIS are supported by cast epoxy insulators. These support
insulators provide a gas barrier between parts of the GIS, or are cast with holes in the epoxy to allow gas
to pass from one side to the other.

Up to about 170 kV system voltage, all three phases are often in one enclosure (Figure 2.2). Above 170 kV, the size of the enclosure for “three-phase enclosure,” GIS becomes too large to be practical. So a “single-phase enclosure” design (Figure 2.1) is used.

There are no established performance differences between three-phase enclosure and single-phase enclosure GIS. Some manufacturers use the single phase enclosure type for all voltage levels.

Enclosures today are mostly cast or welded aluminum, but steel is also used. Steel enclosures are painted inside and outside to prevent rusting. Aluminum enclosures do not need to be painted, but may be painted for ease of cleaning and a better appearance. The pressure vessel requirements for GIS enclosures are set by GIS standards (IEEE Std. C37.122-1993; IEC, 1990), with the actual design, manufacture, and test following an established pressure vessel standard of the country of manufacture.

Because of the moderate pressures involved, and the classification of GIS as electrical equipment, third-party inspection and code stamping of the GIS enclosures are not required.

Conductors today are mostly aluminum. Copper is sometimes used. It is usual to silver plate surfaces that transfer current. Bolted joints and sliding electrical contacts are used to join conductor sections. There are many designs for the sliding contact element. In general, sliding contacts have many individually sprung copper contact fingers working in parallel. Usually the contact fingers are silver plated.

A contact lubricant is used to ensure that the sliding contact surfaces do not generate particles or wear out over time. The sliding conductor contacts make assembly of the modules easy and also allow for conductor movement to accommodate the differential thermal expansion of the conductor relative to the enclosure.

Sliding contact assemblies are also used in circuit breakers and switches to transfer current from the moving contact to the stationary contacts. Support insulators are made of a highly filled epoxy resin cast very carefully to prevent formation of voids and/or cracks during curing.

Each GIS manufacturer’s material formulation and insulator shape has been developed to optimize the support insulator in terms of electric field distribution, mechanical strength, resistance to surface electric discharges, and convenience of manufacture and assembly. Post, disc, and cone type support insulators are used.

Quality assurance programs for support insulators include a high voltage power frequency withstand test with sensitive partial discharge monitoring. Experience has shown that the electric field stress inside the cast epoxy insulator should be below a certain level to avoid aging of the solid dielectric material.

The electrical stress limit for the cast epoxy support insulator is not a severe design constraint because the dimensions of the GIS are mainly set by the lightning impulse withstand level and the need for the conductor to have a fairly large diameter to carry to load current of several thousand amperes. The result is space between the conductor and enclosure for support insulators having low electrical stress.

Service life of GIS using the construction described above has been shown by experience to be more than 30 years. The condition of GIS examined after many years in service does not indicate any approaching limit in service life.

Experience also shows no need for periodic internal inspection or maintenance. Inside the enclosure is a dry, inert gas that is itself not subject to aging. There is no exposure of any of the internal materials to sunlight. Even the “O” ring seals are found to be in excellent condition because there is almost always a “double seal” system. The lack of aging has been found for GIS, whether installed indoors or outdoors.