The capacitor motor is slightly different from a split-phase motor. A capacitor is placed in the path of the electrical current in the start winding (see Fig. 12-13).

(A) Single-phase diagram for the AH air conditioner and heat-pump compressor. (Tecumseh) (B) Terminal box showing the position of the terminals on the AH series of compressors. (Courtesy of Tecumseh)

Except for the capacitor, which is an electrical component that slows any rapid change in current, the two motors are the same electrically.

A capacitor motor can usually be recognized by the capacitor can or housing that is mounted on the stator (see Fig. 12-14).

Adding the capacitor to the start winding increases the effect of the two-phase field described in connection with the split-phase motor. The capacitor means that the motor can produce a much greater twisting force when it is started. It also reduces the amount of electrical current required during starting to about 1.5 times the current required after the motor is up to speed. Split-phase motors require three or four times the current in starting that they do in running.

Reversibility. An induction motor will not always reverse while running. It may continue to run in the same direction, but at a reduced efficiency. An inertia-type load is difficult to reverse.

Most motors that are classified as reversible while running will reverse with a non-inertial-type load. They may not reverse if they are under no-load conditions or have a light lead or an inertial load.

One problem related to the reversing of a motor while it is still running is the damage done to the transmission system connected to the load. In some cases, it is possible to damage a load. One way to avoid this is to make sure the right motor is connected to a load.

Reversing (while standing still) the capacitor-start motor can be done by reversing its start winding connections. This is usually the only time that a field technician will work on a motor.

The available replacement motor may not be rotating in the direction desired, so the technician will have to locate the start winding terminals and reverse them in order to have the motor start in the desired direction.

Uses. Capacitor motors are available in sizes from 1/6 to 20 horsepower. They are used for fairly hard starting loads that can be brought up to run speed in under 3 seconds. They may be used in industrial machine tools, pumps, air conditioners, air compressors, conveyors, and hoists.

Figure 12-15 shows a capacitor-start, induction-run motor used in a compressor. This type uses a relay to place the capacitor in and out of the circuit.

Figure 12-16 shows how the capacitor is located outside the compressor.


Capacitance switching currents may include part or all of the operating duty of a circuit breaker, such as the charging current of an unloaded transmission line or cable or the load current of a shunt capacitor bank. The rating of a circuit breaker for capacitance current switching shall include, where applicable,

a) Rated line-charging breaking current applicable to all outdoor circuit breakers
b) Rated cable-charging breaking current applicable to all indoor circuit breakers
c) Rated single capacitor bank breaking current
d) Rated back-to-back capacitor bank breaking current
e) Rated back-to-back capacitor bank inrush making current and frequency

Preferred values of rated capacitance switching currents are given in Table 1A, Table 2A, and Table 3A of ANSI C37.06-2000. The recovery voltage related to capacitance current switching depends on

The grounding of the system
The grounding of the capacitive load, e.g., shielded cable, capacitor bank, transmission line
The mutual influence of adjacent phases of the capacitive load, e.g., belted cables, open air lines
The mutual influence of adjacent systems of overhead lines on the same route
The presence of single- or two-phase ground faults Two classes of circuit breakers are defined according to their restrike performances:

Class C1: low probability of restrike during capacitance current breaking
Class C2: very low probability of restrike during capacitance current breaking

Each capacitance current switching rating assigned [see item a) through item d) in this subclause] must have an associated class (i.e., C1 or C2) with it.

1—The probability is related to the performance during the series of type tests stated in 4.10 in IEEE PC37.09a and subsequently in 4.10.1 through 4.10.12.

2—A circuit breaker can be of Class C2 for one kind of application (e.g., in grounded neutral systems) and of Class C1 for another kind of application where the recovery voltage stress is more severe (e.g., in systems other than grounded neutral systems).

3—Circuit breakers with a restrike probability other than the probability of Class C1 or Class C2 are not covered by this standard.


A GFCI monitors the current balance between the ungrounded “hot” conductor and the grounded conductor. As soon as the current flowing throughthe “hot” conductor is in the range of 4 to 6 milliamperes more than the current flowing in the “return” grounded conductor, the GFCI senses this unbalance and trips (opens) the circuit off.

The unbalance indicates that part of the current flowing in the circuitis being diverted to some path other than the normal return path along the grounded return conductor. If the “other” path is through a human body, as , the outcome could be fatal.

UL Standard No. 943 covers ground-fault circuit interrupters.

• Class “A” GFCI devices are the most common. They are designed to

– trip when current to ground is 6 milliamperes (6/1000 of an ampere) or greater.

– not trip when the current to ground is less than 4 milliamperes (4/1000 of an ampere).

– may or may not trip when the current to ground is between 4 and 6 milliamperes.

– will open very quickly, in approximately 25 milliseconds.

• Class “B” GFCI devices are pretty much obsolete. They were designed to trip on ground faults of 20 milliamperes (20/1000 of an ampere) or more.

They were used only for underwater swimming pool lighting installed before the adoption of the 1965 NEC. For this application, Class “A” devices were too sensitive and would nuisance trip.

What a GFCI Does Not Do
• It does not protect against electrical shock when a person touches both circuit conductors at the same time (two “hot” wires, or one “hot” wire and one grounded neutral conductor) because the current flowing in both conductors is the same.

Thus, there is no unbalance of current for the GFCI to sense and trip.

• It does not limit the magnitude of ground-fault current. It does limit the length of time that a ground fault will flow. The GFCI should trip in about 25 milliseconds.

In other words, you will still receive a severe shock during the time it takes the GFCI device to trip “off.”

• It does not sense solid short circuits between the “hot” conductor and the grounded “neutral” conductor. The branch-circuit fuse or circuit breaker provides this protection.

• It does not sense solid short circuits between two “hot” conductors. The branch-circuit fuse or circuit breaker provides this protection.

• It does not sense and protect against the damaging effects of arcing faults, such as would occur with frayed extension cords.

This protection is provided by an arc-fault circuit interrupter (AFCI).

• It does not provide overload protection for the branch-circuit wiring. It provides ground-fault protection only.


A voltage regulator is used to hold the voltage of a circuit at a predetermined value, within a band which the control equipment is capable of maintaining and within accepted tolerance values for distribution purposes.

Regulators may be installed at substations or out on distribution feeders on poles, pads, or platforms or in vaults.

Voltage regulators are essentially autotransformers, with the secondary (or series) portion of the coil arranged so that all or part of its induced voltage can be added to or subtracted from the line or incoming primary voltage (across which the primary or exciting portion of the winding is connected).

The voltage variations are accomplished by changing the ratio of transformation automatically without deenergizing the unit.

There are two types of voltage regulators in use in distribution systems: the induction regulator and the tap-changing-under-load (TCUL), or step-type, regulator.

The first is usually limited to circuits operating at 5000 V or less and is being rapidly replaced by the latter, employed where relatively larger amounts of power and higher voltages are involved.

Induction Type Voltage Regulator
In the induction type of voltage regulator, the primary (high-voltage) winding and the secondary (or series) windings are so arranged that they rotate with respect to one another (Figure 12-1). The primary coil is usually the stator and the secondary coil the rotor, the direction of rotation generally depending on whether the incoming voltage is to be raised or lowered.

The voltage induced in the secondary or series winding will depend on the position in relation to the primary winding. Depending on the position, the induced voltage can add to or subtract from the input voltage to obtain the outgoing voltage.

During the rotation of the primary coil, the moving magnetic field can cause a large reactance voltage drop in the secondary. To dampen (or cancel) this effect, a third coil is mourned at right angles to the primary coil on the movable core and short-circuited on itself.

The moving primary coil will induce a voltage in the third coil which will, in turn, set up a moving magnetic field of its own, which will tend to oppose that set up by the motion of the primary coil. The reactance of the regulator unit is thus kept essentially constant.

Step-Type (or TCUL) Regulator
The TCUL, or step-type, regulator is also essentially an autotransformer, and is connected in the circuit in the same manner as the induction regulator. This type does not employ rotation of one of the coils, but changes voltages by means of taps in the primary coil, as shown schematically in Figure 12-2.

The portion of the coil with taps is a separate part of the primary coil with arrangements included for a reversal in its connection so that the voltage within that portion of the primary coil can be added to or subtracted from the voltage in the rest of the primary coil.

Each tap is changed by the opening and closing of an associated “selector” switch. To avoid disconnecting the transformer from the line each time a tap is changed, the taps are so arranged that two adjacent taps are connected through a small autotransformer each time the tap change is in progress.

The midpoint of this “preventive” autotransformer is connected to the primary coil, as illustrated in Figure 12-3.

A small air gap is inserted in the core of the autotransformer to reduce the size of the magnetic field, which could cause an excessive voltage drop in the coil. Small circuit breakers, known as transfer switches, make and break the circuit under oil.

The selector switches are always closed while the corresponding transfer switch is open, and opened while the transfer switch is closed. In this design, three transfer switches and one selector switch for each tap are required for operation.

The transfer switches are often contained in a separate compartment attached to the main tank of the regulator so that they may be maintained without the necessity of draining the oil from the entire regulator unit. The oil in this compartment may be more readily contaminated because of the frequency of the switches’ operation.

The sequence of operation of both the selector and transfer switches is shown in Table 12-1. The switches are operated in proper sequence by a motor-operated mechanism which may be controlled manually or automatically. A time-delay device prevents short-duration dips from operating the control relays.


Lightning or surge arresters consist basically of an air gap in series with another element which has the special characteristic of providing a relatively low resistance or impedance to the current produced by a high voltage surge, and a high resistance or impedance to the flow of power current at the relatively low operating voltage of the distribution line to which it is connected. In some later units, the air gap may be omitted.

Pellet Type
In the pellet type of arrester, the second element is made up of a tube full of lead pellets. The lead pellets are actually lead peroxide coated with lead oxide. The pellets normally act as insulation preventing current from flowing to ground.

When a high-voltage surge is impressed on them, a current will flow that heats them and turns the lead oxide (a poor conductor) into lead peroxide (a good conductor). After the surge is discharged to ground, the surface of the pellets is changed by the discharge current back to lead oxide and restores the arrester to its original condition. Although rapidly becoming obsolete, a great many of this type of arrester exist and will for a long time.

Valve Type
In the valve type of arrester, the second element may be made of some particular substance such as ceramic material containing conducting particles, such as metal oxides (Thyrite and Cranulon are commercial names), or other substances having characteristics under surge-voltage conditions similar to those described above. Many of these are built in modular units, several connected in series to accommodate the line voltage impressed on them.

Expulsion Type
The expulsion type of arrester mayor may not employ a second air gap enclosed in a tube made of fiber in series with a fixed air gap. As with fuse holders made of fiber, when a high voltage occurs creating an arc across the gap, the heat acting on the fiber gives off a nonconducting gas under pressure that blows out the arc, interrupting the flow of surge current and restoring the arrester to its original condition.

Standard arresters are rated not only on the nominal voltage class of the line to which they are to be connected, but also as to the crest voltage (the basic impulse insulation level) they can withstand. Table 11-1 lists some standard ratings for surge arresters associated with distribution circuits of various voltage classes.\

Table 11-1. Standard ratings of surge arresters for distribution voltages.


The Canadian Electrical Code is significantly different from the National Electrical Code. It is considered Part 1 of the Canadian Electrical Code.

Part 2 of the Canadian Electrical Code consists of electrical product safety standards similar to the standards produced in the United States by Underwriters Laboratories. Canadian product safety standards are produced by the Canadian Standards Association (CSA).

In fact, many of the Canadian and U.S. standards have been harmonized. This allows a product to be evaluated and listed to the same requirements in both countries. Efforts are continuing to harmonize U.S. and Canadian standards with those from Mexico.

CSA also serves as a third-party independent electrical products testing laboratory. Manufacturers are permitted to use a listing mark to identify products that have been found by examination and testing to comply with the Canadian Electrical Code Part Two.

CSA’s listing mark is shown in Figure 1-12 and is arranged identically to UL’s listing mark to designate suitability of the product for installation in the United States or Canada.

Those using this text in Canada must follow the Canadian Electrical Code. Electrical Wiring— Commercial (© Thomas Nelson Holdings) is available based on the Canadian Electrical Code.

The Canadian Electrical Code is a voluntary code suitable for adoption and enforcement by electrical inspection authorities. The Canadian Electrical Code is published by and available from:

CSA International
178 Rexdale Boulevard
Toronto, Ontario, Canada
M9W 1R3
Fax: 416-747-4149


Numerous types of structure are used for supporting transmission line conductors, for example, self-supporting steel towers, guyed steel towers, self-supporting aluminum towers, guyed aluminum towers, self-supporting steel poles, flexible and semiflexible steel towers and poles, rope suspension, wood poles, wood H frames, and concrete poles.

The type of supporting structure to use depends on such factors as the location of the line, importance of the line, desired life of the line, money available for initial investment, cost of maintenance, and availability of material.

Because of the wide conductor spacing required for electrical clearances and insulation, the high tensile stresses used in conductors and ground cables to pull these cables up to a sag which will keep the heights of the structures within reason, the long spans necessary for crossing ravines in mountainous country, and the reliance to be placed on a major trunk line, lines exceeding 345 kV are frequently built of self-supporting steel towers although guyed and rope-suspension structures are increasingly applied.

A line built with self-supporting steel towers is very satisfactory in all respects, as it requires less inspection and has a maximum life with minimum maintenance costs. However, high-strength aluminum-alloy towers are available, and their use is on the increase.

They have the advantage of better resistance to corrosive atmospheres than steel.74 The structural configurations and design details are the same as with steel, with the added problem of greater deflections when stresses are applied owing to the lower modulus of elasticity of aluminum.

The effect of long-time creep of aluminum is yet to be determined. Self-supporting steel poles are frequently used in congested districts where right-of-way is limited and short spans are necessary. The advent of EHV has brought a great variety of new structural configurations.

Details of some of these have been published. Electrical World, Nov.15, 1965, pp. 95–118, contains outline drawings of 35 towers and six wood-pole H-frame structures as applied to EHV, as well as a tabulation of specification items of EHV lines in the United States and Canada. The Transmission Line Reference Book, 345 kV and Above, 2d ed., 1982, published by EPRI,3 contains details of a broad spectrum of 345 through 800-kV structures.

Wood poles are used extensively where they are readily available. Medium- and lower-voltage lines can be built economically with such poles fitted with either steel or wood crossarms. Wood H frames composed of two poles tied together at the top with wood or steel crossarms have been successfully used for the higher-voltage lines up to 345 kV. To take full advantage of the transverse strength, such poles can be braced internally for at least a portion of their height with wood X bracing.

Concrete poles have been used in some parts of the world where timber is scarce and where the ingredients for making concrete are readily obtainable. Another advantage is that they are impervious to insect damage and other forms of decay prevalent with wood structures in tropical or subtropical climates.

They are generally cast in units, by using standard forms, and transported to the site, although they may be manufactured where used. Concrete poles should always have sufficient prestressed steel reinforcement to take care of the bending stresses due to wind loads, pulls from cables, and the like, in addition to being designed as columns under vertical loads. In all structures conductor configuration and the effect of various forces which may act upon them must be taken into


Wake-induced oscillation is limited to lines having bundled conductors and results from aerodynamic forces on the downstream conductor of the bundle as it moves in and out of the wake of the upstream conductor.

Wake-induced oscillation is controlled by maintaining sufficiently large conductor spacing in the bundle, unequal subspan lengths, and tilting the bundles.

Bundled conductors are subject to wake-induced oscillations with amplitudes and frequencies typically between that of eolian vibration and galloping. The frequencies of oscillation are normally in the range of 1 to 10 Hz, and the amplitudes are in the range of 10 conductor diameters.

The modes in which such vibration occurs are considerably more complex than the modes exhibited during either galloping or the almost invisible eolian vibrations. The source of wind energy for wake-induced oscillation is, as the name suggests, the wake from the windward conductor of the bundle which causes the motion of the downwind conductor.

There are three basic approaches to the control of wake-induced oscillation. Two involve reducing the input of wind energy, and the third involves detuning the mechanical bundle system to prevent resonance.

The methods based on reducing wind energy input to the bundle are bundle tilting and bundle sizing. By tilting the bundle to angles of 20 or more, the downwind conductors are moved to the edge of the upwind conductor’s wake and the energy input is reduced.

By keeping the subconductor spacing to the order of 20 times the conductor diameter, the wind energy input to the windward conductor is reduced by being moved to a wake region of reduced intensity.

The third commonly used method to control or eliminate wake-induced oscillations is to stagger the length or simply to shorten the average subspan length. This method does not control those oscillations where the bundle moves as a rigid body and is somewhat dependent on the mechanical characteristics of the spacers.

In comparison to the damage that can result from eolian vibration or galloping, field reports of wake-induced oscillation damage are usually of a minor nature, primarily conductor abrasion from clashing and spacer breakage, neither of which normally results in system outages.


Eolian vibration can occur when conductors are exposed to a steady low-velocity wind. If the amplitude of such vibration is sufficient, it can result in strand fatigue and/or fatigue of conductor accessories.

The amplitude of vibration can be reduced by reducing the conductor tension, adding damping by using dampers (or clamps with damping characteristics), or by the use of special conductors which either provide more damping than standard conductors or are shaped so as to prevent resonance between the tensioned conductor span and the wind-induced vibration force.

Eolian Vibration. As wind blows across a conductor, vortices are shed from the top and bottom of the conductor. The vortex shedding is accompanied by a varying pressure on the top and bottom of the conductor that encourages cyclic vibration of the conductor perpendicular to the direction of wind flow.

The frequency at which this alternating pressure occurs is given by the expression

     f = 3.26 x U/d

where U wind speed, mi/h
d conductor diameter, in
f frequency, Hz

For a 1.0-in-diameter conductor exposed to a 10-mi/h wind, the vortex shedding force oscillates at 32.6 Hz. To develop significant amplitudes, there must be a resonance between this oscillating wind force and the vibrating catenary (conductor).

The fundamental frequency of vibration of the suspended conductor is in the range of 0.1 to 1.0 Hz. Therefore, the eolian vibration force will be unlikely to excite a fundamental span mode. This is verified by actual conductor performance where significant amplitudes are usually observed for frequencies in the range of 10 to 100 Hz.

Practical wind speeds cause vortex shedding forces of greater than 10 Hz, eliminating frequencies below this level, and frequencies above 100 Hz are not present because of the rapid increase in conductor selfdamping for these higher frequencies.

The maximum alternating stress resulting in strand fatigue normally occurs at the conductor clamp. The stress is related to the amplitude of conductor vibration and is the amplitude normally measured by field recording devices. Stress and amplitude of vibration can be related by analytical means such as the Poffenberger Swart formula.

The amplitude of eolian vibration is fixed by the balance of energy input from the wind-induced vortex shedding forces and the energy loss due to conductor, accessory, and structure damping. The addition of dampers to the conductor has been established as an effective means of control. Special conductors such as SDC and SSAC have also been shown effective in reducing the strand stress levels.

Another effective means of limiting vibration fatigue problems is to increase the self-damping of standard conductors by reducing tension. As a practical approximation, stringing conductors to a final unloaded tension of 15% or less at the minimum seasonal average temperature (usually 0 to 30 F) will prevent vibration fatigue problems.

Higher tensions are routinely used in areas where the line is parallel to existing lines and the higher tension on the existing line has not resulted in problems. The use of vibration dampers or special anti vibration conductors can also allow the use of higher tension levels.

As with single conductors, bundled conductors are subjected to eolian vibration. However, the interaction of conductors in the bundle due to slightly different tensions and increased damping from spacers results in lower vibration levels for bundles than for single conductors in the same wind exposure.


Color Coding (Cable Wiring)
The conductors in nonmetallic-sheathed cable (Romex) are color coded with insulation as follows:

2-wire: one black (“hot” phase conductor)one white (grounded “identified” conductor)one bare, covered, or insulated (equipment grounding conductor)

3-wire: one black (“hot” phase conductor) one white (grounded “identified” conductor) one red (“hot” phase conductor) one bare, covered, or insulated (equipment grounding conductor)

4-wire: one black (“hot” phase conductor) one white (grounded “identified” conductor) one red (“hot” phase conductor) one blue (“hot” phase conductor) one bare, covered, or insulated (equipment grounding conductor)

Four-wire nonmetallic-sheathed cable is also available with two ungrounded (“hot”) and two neutral conductors. This cable is designed for wiring two 120-volt branch circuits without using a common neutral.

This avoids the requirement of installing a tie handle on the circuit breakers or installing a 2-pole circuit breaker. This cable has the following insulated conductors:

• one black (“hot” phase conductor)
• one white with a black stripe (grounded “identified” conductor)
• one red (“hot” phase conductor)
• one white with a red stripe (“hot” phase conductor)
• one bare, covered, or insulated (equipment grounding conductor)

Manufacturers of Type MC cable also make a “home run cable.” This cable is available with 6 or 8 12 AWG conductors and with 6, 8, 12, and 16 10 AWG conductors. The insulation is THHN/THWN, so
derating [required by NEC 310.15(B)(3)] is started in the 90°C column of NEC Table 310.15(B) (16).

Table 5-1 illustrates application of derating for the number of current-carrying conductors in the home run cable. Notice that the number of currentcarrying conductors can change depending on how connections are made.


Design of any system should always be preceded by a formal determination of the business and corresponding technical requirements that drive the design. Such a formal statement is known as a “functional requirements specification.”

Functional requirements capture the intended behavior of the system. This behavior can be expressed as services, tasks, or functions the system is required to perform.

In the case of SCADA, the specification contains such information as system status points to be monitored, desired control points, and analog quantities to be monitored. It also includes identification of acceptable delays between when an event happens and when it is reported, required precision for analog quantities, and acceptable reliability levels.

The functional-requirements analysis will also include a determination of the number of remote points to be monitored and controlled. It should also include identification of communication stakeholders other than the control center, such as maintenance engineers and system planners who may need communication with the substation for reasons other than real-time operating functionality.

The functional-requirements analysis should also include a formal recognition of the physical, electrical, communications, and security environment in which the communications are expected to operate.

Considerations here include recognizing the possible (likely) existence of electromagnetic interference from nearby power systems, identifying available communications facilities, identifying functionally the locations between which communications are expected to take place, and identifying potential communication security threats to the system.

It is sometimes difficult to identify all of the items to be included in the functional requirements. A technique that has been found useful in the industry is to construct a number of example “use cases” that detail particular individual sets of requirements. Aggregate use cases can form a basis for a more formal collection of requirements.


The insulation of the cable must be able to withstand the voltage stresses experienced during normal and abnormal operating conditions. Therefore the selection of the cable insulation should be made on the basis of the applicable phase-to-phase voltage and the general system category which are classified as either 100%, 133%, or 173% insulation levels.

These insulation levels are discussed as follows:

1. 100% level: Cables in this category may be applied where the system is provided with relay protection which normally clears ground faults within 1 min. This category is usually referred to as the grounded systems.

2. 133% level: Cables in this category may be applied where the system is provided with relay protection which normally clears ground faults within 1 h. This category is usually referred to as the low resistance grounded, or ungrounded systems.

3. 173% level: Cables in this category may be applied where the time needed to de-energize the ground fault is indefinite. This level is recommended for ungrounded and for resonant grounded systems.

The current capacity that the cable needs to carry is determined by the load it serves. The NEC is very specific in terms of sizing conductors for systems operating below 600 V.

The current-carrying ability of cable is based upon an operating ambient temperature. When cables are installed in multiple duct banks, it is essential to derate the cable current capacity in order not to exceed its thermal rating.

In cases where cables may be load cycled, the currentcarrying capacity may be calculated by the following formula:

Ieq = Ei^2t/T

Ieq is the equivalent current-carrying capacity
I is the constant current for a particular time period
t is the time period of constant current
T is the total time of duty cycle
E is the voltage of the cable

The equivalent current-carrying capacity should be used for selecting the conductor size for thermal withstand.


A wide variety of finishes are used; they are referred to as jackets, sheaths, armors, and braids. These coverings are required primarily because of the physical or chemical characteristics of the particular insulation involved and the required mechanical protection. Finishes can be divided into two categories:
(1) metallic finishes and (2) nonmetallic finishes.

Metallic Finishes
Metallic armor should be applied where a high degree of mechanical protection is required along with protection from rodents, termites, and the like. All metallic sheaths are subject to electrolytic damage. Metallic finishes are subdivided into the following:

1. Lead sheaths: One of the earliest types of metallic sheaths still in use.

2. Flat-band armor: Consists of jute bedding, two helical tape wraps, and a protective jute covering over the tapes. The tape may be either galvanized or plain steel.

3. Interlocked armor: Consists of galvanized steel, aluminum, or bronze strip (0.750 in. wide and 0.020–0.030 in. thick) over the cable in such a way as to provide excellent protection.

4. Aluminum-sheathed cable: A recently introduced cable that offers advantages such as lightweight, resistance to fatigue, good corrosion resistance, and positive moisture barrier.

5. Wire armor: Available in two types, round and basket-weave or braided wire. Round wire armor offers extremely strong cable and has high tensile strength for vertical applications. Braided or basket-weave wire armor consists of a braid of metal wire woven directly over the cable as an outer covering where additional mechanical strength is required.

Nonmetallic finishes
Most of the nonmetallic finishes include PVC, PE, neoprene, hyplon, and EPR.
1. PVC: This covering (i.e., finish) offers excellent moisture-resistance characteristics, but does not provide mechanical protection.

2. PE: It has excellent resistance to water, ozone, and oxidation. It is resistant to gasoline, solvents, and flames.

3. Neoprene: It is commonly recommended where service conditions are usually abrasive and extreme. By itself, it is not flame retardant.

4. Hyplon: It possesses similar properties as neoprene, but also has better thermal stability and resistance to ozone and oxidation.

5. EPR: It exhibits excellent weathering properties and is resistant to ozone. It has good chemical and mechanical properties, but is not inherently flame retardant.

6. Braids: Generally, present-day trends are away from the use of nonmetallic braid coverings. Braids may be of the following types:
a. Heat- and moisture-resistant cotton braid
b. Flame-resistant cotton braid
c. Asbestos braid


This type of cable can be classified as follows:
1. NEC compounds
2. Elastomers
3. Thermoplastics
4. Thermosettings

The rubber and rubber-like insulated cables enjoy their popularity owing to moisture resistance, ease of handling, ease of splicing, and extreme flexibility.

Elastomers are materials that can be compressed, stretched, or deformed like rubber and yet retain their original shape. The thermoplastics materials soften when they are reheated, whereas thermosetting-type insulation has very little tendency to soften upon reheating after vulcanization.

The earlier oil-based natural rubber compounds have been replaced by synthetic materials, which have better electrical and mechanical characteristics. The following synthetic rubber-like compounds are in use today:

Ethylene propylene rubber (EPR), an elastomer compound: EPR is commonly used in power cables, but is also gaining use in telecommunications and other types of cables. EPR possesses good chemical, mechanical, and electrical properties. However, it is not inherently flame retardant. It has a maximum operating temperature of 90°C, and maximum rated voltage (phase–phase) of 138 kV.

Neoprene, an elastomer compound: Neoprene is one of the most common materials in use for cable jackets. It is used where service conditions are usually abrasive. Since neoprene is not inherently flame retarding, it is usually compounded with the necessary flame retarding chemicals when used as cable jackets.

Hypalon, an elastomer compound: Hypalon is also a commonly used material for cable jackets. It has properties similar to neoprene, and in addition exhibits better thermal stability and resistance to ozone
and oxidation.

Polyvinyl chloride (PVC), a thermoplastic compound: It is flexible, has good electrical properties, and requires no external jacket. Cables using this insulation are rated up to 600 V; maximum operating temperature is 60°C for power applications; maximum short-circuit rating temperature is 150°C. NEC designation is T, TW. It is available in several colors and is mainly used as low-voltage cable systems.

Polyethylene (PE), a thermoplastic compound: It melts at very low temperatures (i.e., 110°C). It is also severely affected by corona. It has a high coefficient of thermal expansion. However, it has excellent electrical and moisture-resistance properties. It has a low cost. Its maximum operating temperature is 75°C and maximum short-circuit temperature is 150°C. It is used in low- and medium-voltage applications.

Buna, a thermosetting compound: It combines the most desirable properties of low-voltage insulation. It has the advantages of heat and moisture resistance, excellent aging qualities, and good electrical characteristics. However, it lacks resistance to ozone. NEC designation is RHW. Its maximum operating temperature is 75°C and shortcircuit temperature is 200°C.

Butyl, a thermosetting compound: It has a high resistance to moisture, heat, and ozone. NEC designation is RHH. It has a maximum operating temperature of 90°C and short-circuit temperature of 200°C.

Silicone rubber, a thermosetting compound: It is extremely resistant to flame, ozone, and corona. It has a maximum operating temperature of 125°C and a maximum short-circuit temperature of 250°C. It has poor mechanical strength.

XLPE, a thermosetting compound: It has excellent electrical properties and high resistance to moisture and chemical contaminants. It is severely affected by corona and has an operating temperature of 90°C. Its short-circuit temperature is 250°C. It can be applied on up to 35 kV distribution systems.


The concentric stranding is most commonly used for power cable conductors. The construction of concentric-type cable consists of a central core surrounded by one or more layers of helically applied wires.

The first layer has six wires and each subsequent layer has six more wires than the preceding layer. In this type of cable construction, the core consists of single wire and all of the strands have the same diameter.

The first layer over the core contains 6 wires, the second contains 12 wires, the third 18, and so on. The following types of strandings are used in this application.

Class B: This class of stranding is used exclusively for industrial power cables for application in 600 V, 5 kV, and 15 kV power systems. The cable stranding usually consists of 7 (#2 AWG), 19 (#4/0 AWG), 37 (500 kcmil), or 61 (750 kcmil) strands.

Classes C and D: These classes are used where a more flexible cable is required. Class C uses 19, 37, 61, or 91 strands and class D uses 37, 61, 91, or 127 strands for the #2 AWG, #4/0 AWG, 500 kcmil, and 750 kcmil cable construction, respectively.

Classes G and H: These classes are used to provide more flexible cable than class D. Classes G and H are also known by rope or bunch stranding. Class G uses 133 strands and class H uses 259 strands for cable construction. Examples of cables in these classes are welding and portable wire for special apparatus or large cables.


Power cables at voltages above 2000 V usually have shielding and semiconducting tape. Cable shielding system consists of “strand shield” and “ insulation shield system.”

Insulation shield system
The insulation shield system is comprised of two conductive components: a semi-conductive layer called “semi-con” and metallic (conductive) layer. The insulation shield system is installed on the outer surface of the insulation and hence is called “the outer shield.”

The purpose of the semi-con is to remove air voids between the metallic shield and the insulation.

Shielding is accomplished by wrapping a thin (0.005 in.) copper tape spirally around the insulation to form a continuous shield along the entire length of the cable.

This tape may or may not be perforated to reduce losses and is held to ground potential by suitable grounding.

Shielding is necessary on medium and HV cables to
1. Prevent damage from corona.
2. Confi ne dielectric fi eld to the inside of cables or conductor insulation.
3. Give symmetrical stress.
4. Reduce induced voltages.
5. Provide increased safety to human life.

The shield must be grounded at one end and preferably at more than one point. The usual practice is to ground the shield at each termination and splice.

Strand shielding (semiconducting tape)
Except on 600 V rubber and varnished cambric cables, semiconducting tape is used to separate the conductor from the rubber insulation to prevent possible damage of the insulation from corona and ionization.

The solid line in Figure 6.1 shows how voltage stress may develop in the air spaces between
conductor strands and insulation, thereby causing the ionization of air and breakdown of cable insulation.

The application of semiconducting tape smooths the voltage stress, as shown by the dashed lines, and keeps such voltage stress constant and to a minimum.

This application of the semiconducting tape is known as “strand shielding.” Modern cables are generally constructed with an extruded strand shield.


The NESC recommends limits on the tension of bare overhead conductors as a percentage of the conductor’s rated breaking strength. The tension limits are: 60% under maximum ice and wind load, 33.3% initial unloaded (when installed) at 60°F, and 25% final unloaded (after maximum loading has occurred) at 60°F.

It is common, however, for lower unloaded tension limits to be used. Except in areas experiencing severe ice loading, it is not unusual to find tension limits of 60% maximum, 25% unloaded initial, and 15% unloaded final.

This set of specifications could easily result in an actual maximum tension on the order of only 35 to 40%, an initial tension of 20% and a final unloaded tension level of 15%. In this case, the 15% tension limit is said to govern.

Transmission-line conductors are normally not covered with ice, and winds on the conductor are usually much lower than those used in maximum load calculations. Under such everyday conditions, tension limits are specified to limit aeolian vibration to safe levels.

Even with everyday lower tension levels of 15 to 20%, it is assumed that vibration control devices will be used in those sections of the line that are subject to severe vibration. Aeolian vibration levels, and thus appropriate unloaded tension limits, vary with the type of conductor, the terrain, span length, and the use of dampers.

Special conductors, such as ACSS, SDC, and VR, exhibit high self-damping properties and may be installed to the full code limits, if desired.


Insulator Washing
Another common practice is to utilize helicopters for insulator washing. Again, this is a method that allows for the line to remain energized during the process.

The helicopter carries a water tank that is refilled at a staging area near the work location. A hose and nozzle are attached to a structure on the helicopter and are operated by a qualified line worker who directs the water spray and adequately cleans the insulator string.

Again, with the ease of access afforded by the helicopter, the speed of this operation can result in a typical three-phase tower being cleaned in a few minutes.

Helicopters are invaluable for tower line and structure inspections. Due to the ease of the practice and the large number of inspections that can be accomplished, utilities have increased the amount of maintenance inspections being done, thus promoting system reliability.

Helicopters typically carry qualified line workers who utilize stabilizing binoculars to visually inspect the transmission tower for signs of rusting or weakness and the transmission hardware and conductor for damage and potential failure.

Infrared inspections and photographic imaging can also be accomplished from the helicopter, either by mounting the cameras on the helicopter or through direct use by the crew. During these inspections, the helicopter provides a comfortable situation for accomplishing the necessary recording of specific information, tower locations, etc.

In addition, inspections from helicopters are required following a catastrophic event or system failure. It is the only logical method of quickly inspecting a transmission system for the exact location and extent of damage.

Helicopter Method Considerations
The ability to safely position a helicopter and worker at the actual work site is the most critical consideration when deciding if a helicopter method can be utilized for construction or maintenance. The terrain and weather conditions are obvious factors, as well as the physical spacing needed to position the helicopter and worker in the proximity required for the work method.

If live-line work methods are to be utilized, the minimum approach distance required for energized line work must be calculated very carefully for every situation. The geometry of each work structure, the geometry of the individual helicopter, and the positioning of the helicopter and worker for the specific work method must be analyzed. There are calculations that are available to analyze the approach distances (IEEE Task Force, 1999).

When choosing between construction and maintenance work methods, the safety of the line workers is the first consideration. Depending on circumstances, a helicopter method may be the safest work method. Terrain has always been a primary reason for choosing helicopters to assist with projects since the ability to drive to each work site may not be possible.

However, helicopters may still be the easiest and most economic alternative when the terrain is open and flat, especially when there are many individual tower locations that will be contacted. Although helicopters may seem to be expensive on a per person basis, the ability to quickly position workers and easily move material can drastically reduce costs.

When live-line methods can be utilized, the positioning of workers, material, and equipment becomes comparatively easier.

Finally, if the safe use of the helicopter allows the transmission systems to remain energized throughout the project, the helicopter may be the only possible alternative. Since the transmission system is a major link in the competitive energy markets, transmission operation will have reliability performance measures which must be achieved.

Purchasing replacement energy through alternate transmission paths, as was done in the regulated world, is no longer an option. Transmission system managers are required to keep systems operational and will be fined if high levels of performance are not attained. The option of deenergizing systems for maintenance practices may be too costly in the deregulated world.


The short answer to the question “What is electricity?” is the transfer of energy through the motion of charge-carrying electrons. Lightning is an example of electricity and of electrons — lots and lots of them — in motion.

Electricians are generally concerned with a much more controlled situation where electricity flows through a given path in a safe, predictable manner, but the electricity we use in shows is no different than that in a lightning strike, a static discharge, or a flashlight battery.

Each is an example of the transfer of energy through the motion of electrons. But from where do these electrons come? The answer can be found in one of the most basic building blocks of the universe, the atom.

For thousands of years, the nature of electricity puzzled and mystified some of the most brilliant minds. It wasn’t until scientists such as Benjamin Franklin, André-Marie Ampère, Alessandro Volta, and Michael Faraday contributed to our understanding of electricity that we began to unlock its secrets.

Step by step, bit by bit, we built a plausible model of electricity that fits a mathematical model and provides a real-world explanation of this phenomenon. Even after we had a basic understanding of the key relationships and the fundamentals of electricity, early pioneers such as Joseph Swan, Thomas Edison, Nikola Tesla, and George Westinghouse still struggled to harness its power for daily use in a safe and efficient manner.

During that time — the late 1800s and early 1900s — one of the first practical uses of electricity was to illuminate common areas such as city streets and town squares. New York City quickly became entangled — quite literally — in electrical wires and electricity. Horrified bystanders witnessed the accidental electrocution of several workers in the naked light of day, and electricity gained a reputation for being both mysterious and dangerous.

Thomas Edison used the public’s fear to protect his economic interests by promoting DC power distribution over AC power distribution, while George Westinghouse grew his business on the strength of AC and its inherent advantages over DC.

The ensuing controversy did nothing to ease the public’s apprehension about electricity, nor did it help to clarify its nature or promote its understanding. To this day, many people have little understanding of the nature of electricity.

Some of us still have difficulty answering the question, “What is electricity?” After all, we can’t see it, hear it, or smell it. And we certainly don’t want to taste it or feel it.

An electrician might understand how to hook up a power distribution system but may not fully understand exactly how electricity behaves.

By studying the fundamentals of electricity we can better understand how to use electricity safely, effectively, and legally.


In electrical parlance, certain terms relating to grounding are commonly confused.

The neutral (the white or gray wire in North America, the blue wire in Europe, the black wire in India and Australia, and the light blue wire in China) is grounded at the panelboard, so it is referred to as a grounded conductor.

None of the phase conductors are grounded, so they are referred to as ungrounded conductors. The grounding conductor is usually the green or green/yellow striped wire, or it can be a bare copper wire in the United States and Canada.

Grounding is a continual process — the system is constantly kept at zero potential — so the green wire is called the grounding wire as opposed to the neutral, which is the grounded conductor.

Bonding is the physical connection between metallic conducting materials in the system such as metal enclosures, conduit, and water pipes.

The components of a power distribution system are bonded to ensure that they remain at ground potential and to provide a low-impedance path to ground.

The grounded wire (neutral) is connected to the grounding wire (green or green/yellow striped wire) using a main bonding jumper in the service-disconnect enclosure.

Of course, the term ground is an American term meaning earth. In other countries, the term earth is used in favor of ground.


In North America, getting an occasional shock by the 120-volt household mains supply is almost a rite of passage. In Europe, where the mains supply is 230V or 240V, getting “bit” by the mains supply might lead to your last rites.

The higher voltage is much more dangerous because it produces more current given the same impedance.

In some parts of Europe, the situation is exacerbated by the fact that the utility companies use a T-T (terra-terra) earthing system whereby the electrical service is grounded at the service entrance or utility pole and at the point of consumption as well.

The ground fault return path is taken to be the earth, and if it happened to be a less than ideal conductor, then so be it. The problem is that if the impedance of the return path for fault currents is high enough, then the current is proportionately lower.

Since the circuit breakers that are supposed to protect the circuit from large short circuit currents have an inverse-time relationship with the current — the larger the current, the faster they act — they will not act as quickly as they would if the grounding conductor or circuit protective conductor were used to create a low-impedance path to the source.

Thus, more damage can occur and personnel are at greater risk. Add to that the smaller, higher impedance wires used there because of the higher voltage and lower currents, and you have a recipe for mishap.

But the Germans, being the clever people they are, invented a solution to help curb the risk. Their earliest solution was to build high-precision “Swiss watch” 4X breakers. Whereas the typical circuit breaker required 7.5 to 20 times the rated current in order to trip instantaneously, the 4X breaker would trip instantaneously at four times its rated current.

These breakers improved the situation but didn’t completely resolve the problem. Their second pass produced a new type of device that would detect ground faults of as little as 500 milliamps. Later, the sensitivity would improve to trip at 100 milliamps, and then improve again to trip at 30 milliamps.

These devices use a donut-shaped current transformer through which all of the current-carrying conductors are run. If the vectorial sum of the outgoing current and the return current is equal to zero, then no control voltage is generated because the magnetic fields of the currents would cancel.

However, in the event of a ground fault, not all of the outgoing current would be returned through the current transformer, thus signaling a problem. The voltage created by the current transformer would be used to trigger the circuit breaker to open.

These so-called residual current devices, or RCDs, helped resolve the problems with ground faults in T-T systems.


Ancillary services support the basic electrical services and are essential for the reliability and operation of the electric power system.

The electrical services that are supported include generating capacity, energy supply, and the power delivery system. FERC requires six ancillary services, including system control, regulation (frequency), contingency reserves (both spinning and supplemental), voltage control, and energy imbalance.

In addition, load following, backup supply, network stability, system ‘‘black-start’’, loss replacement, and dynamic scheduling are necessary for the operation of the system.

Utilities have been performing these functions for decades, but as vertically integrated regulated monopoly organizations. As these begin to disappear, and a new structure with multiple competing parties emerges, distributed utilities might be able to supply several of these.

The distributed utilities providing these services could be owned by the former traditional utility, customers, or third-party brokers, depending on the application. The main obstacles to this approach are aggregation and communication when dealing with many small resources rather than large central station sources.


The electrolyte defines the key properties, particularly the operating temperature, of the fuel cell. Consequently, fuel cells are classified based on the types of electrolyte used as described below.

1. Polymer Electrolyte Membrane (PEM)
2. Alkaline Fuel Cell (AFC)
3. Phosphoric Acid Fuel Cell (PAFC)
4. Molten Carbonate Fuel Cell (MCFC)
5. Solid Oxide Fuel Cell (SOFC)

These fuel cells operate at different temperatures and each is best suited to particular applications.

Polymer Electrolyte Membrane (PEM)
The PEM cell is one in a family of fuel cells that are in various stages of development. It is being considered as an alternative power source for automotive application for electric vehicles.

The electrolyte in a PEM cell is a type of polymer and is usually referred to as a membrane, hence the name. Polymer electrolyte membranes are somewhat unusual electrolytes in that, in the presence of water, which the membrane readily absorbs, the negative ions are rigidly held within their structure.

Phosphoric Acid Fuel Cell (PAFC)
Phosphoric acid technology has moved from the laboratory research and development to the first stages of commercial application. Turnkey 200-kW plants are now available and have been installed at more than 70 sites in the U.S., Japan, and Europe. Operating at about 2008C, the PAFC plant also produces
heat for domestic hot water and space heating, and its electrical efficiency approaches 40%.

The principal obstacle against widespread commercial acceptance is cost. Capital costs of about $2500 to$4000=kW must be reduced to $1000 to $1500=kW if the technology is to be accepted in the electric power markets.

Molten Carbonate Fuel Cell (MCFC)
Molten carbonate technology is attractive because it offers several potential advantages over PAFC. Carbon monoxide, which poisons the PAFC, is indirectly used as a fuel in the MCFC. The higher operating temperature of approximately 6508C makes the MCFC a better candidate for combined cycle applications whereby the fuel cell exhaust can be used as input to the intake of a gas turbine or the boiler of a steam turbine.

The total thermal efficiency can approach 85%. This technology is at the stage of prototype commercial demonstrations and is estimated to enter the commercial market by 2003 using natural gas, and by 2010 with gas made from coal. Capital costs are expected to be lower than PAFC. MCFCs are now being tested in full-scale demonstration plants.

Solid Oxide Fuel Cell (SOFC)
A solid oxide fuel cell is currently being demonstrated at a 100-kW plant. Solid oxide technology requires very significant changes in the structure of the cell. As the name implies, the SOFC uses a solid electrolyte, a ceramic material, so the electrolyte does not need to be replenished during the operational life of the cell.

This simplifies design, operation, and maintenance, as well as having the potential to reduce costs. This offers the stability and reliability of all solid-state construction and allows higher temperature operation.

The ceramic make-up of the cell lends itself to cost-effective fabrication techniques. The tolerance to impure fuel streams make SOFC systems especially attractive for utilizing H2 and CO from natural gas steam-reforming and coal gasification plants.


The fuel cell works by processing a hydrogen-rich fuel—usually natural gas or methanol—into hydrogen, which, when combined with oxygen, produces electricity and water. This is the reverse electrolysis process.

Rather than burning the fuel, however, the fuel cell converts the fuel to electricity using a highly efficient electrochemical process. A fuel cell has few moving parts, and produces very little waste heat or gas.

A fuel cell power plant is basically made up of three subsystems or sections. In the fuel-processing section, the natural gas or other hydrocarbon fuel is converted to a hydrogen-rich fuel. This is normally accomplished through what is called a steam catalytic reforming process.

The fuel is then fed to the power section, where it reacts with oxygen from the air in a large number of individual fuel cells to produce direct current (DC) electricity, and by-product heat in the form of usable steam or hot water.

For a power plant, the number of fuel cells can vary from several hundred (for a 40-kW plant) to several thousand (for a multi-megawatt plant). In the final, or third stage, the DC electricity is converted in the power conditioning subsystem to electric utility-grade alternating current (AC).

In the power section of the fuel cell, which contains the electrodes and the electrolyte, two separate electrochemical reactions take place: an oxidation half-reaction occurring at the anode and a reduction half-reaction occurring at the cathode.

The anode and the cathode are separated from each other by the electrolyte. In the oxidation half-reaction at the anode, gaseous hydrogen produces hydrogen ions, which travel through the ionically conducting membrane to the cathode. At the same time, electrons travel through an external circuit to the cathode.

In the reduction half-reaction at the cathode, oxygen supplied from air combines with the hydrogen ions and electrons to form water and excess heat. Thus, the final products of the overall reaction are electricity, water, and excess heat.


The gas-insulated transmission line (GIL) was invented in 1974 to connect the electrical generator of a hydro pump storage plant in Schluchsee, Germany. The GIL went into service in 1975 and has remained in service without interruption since then, delivering peak energy into the southwestern 420 kV network in Germany.

With 700 m of system length running through a tunnel in the mountain, this GIL is still the longest application at this voltage level in the world. Today, at high-voltage levels ranging from 135 to 550 kV, a total of more than 100 km of GILs have been installed worldwide in a variety of applications, e.g., inside high-voltage substations or power plants or in areas with severe environmental conditions.

Typical applications of GIL today include links within power plants to connect high-voltage transformers with high-voltage switchgear, links within cavern power plants to connect high-voltage transformers in the cavern with overhead lines on the outside, links to connect gas-insulated substations (GIS) with overhead lines, and service as a bus duct within gas-insulated substations.

The applications are carried out under a wide range of climate conditions, from low-temperature applications in Canada, to the high ambient temperatures of Saudi Arabia or Singapore, to the severe conditions in Europe or in South Africa.

The GIL transmission system is independent of environmental conditions because the highvoltage system is completely sealed inside a metallic enclosure. The GIL technology has proved its technical reliability in more than 2500 km years of operation without a major failure.

This high system reliability is due to the simplicity of the transmission system, where only aluminum pipes for conductor and enclosure are used, and the insulating medium is a gas that resists aging. The high cost of GILs has restricted their use to special applications.

However, with the second generation GIL, a total cost reduction of 50% has made the GIL economical enough for application over long distances. The breakthrough in cost reduction is achieved by using highly standardized GIL units combined with the efficiencies of automated orbital-welding machines and modern pipeline laying methods.

This considerably reduces the time required to lay the GIL, and angle units can be avoided by using the elastic bending of the aluminum pipes to follow the contours of the landscape or the tunnel. 

This breakthrough in cost and the use of N2/SF6 gas mixtures have made possible what is now called second-generation GIL, and it is a very interesting transmission system for high-power transmission over long distances, especially if high power ratings are needed.

The second-generation GIL was first built for eos (energie ouest suisse) at the PALEXPO exhibition area, close to the Geneva Airport in Switzerland. Since January 2001, this GIL has been in operation as part of the overhead line connecting France with Switzerland. 

The success of this project has demonstrated that the new laying techniques are suitable for building very long GIL transmission links of 100 kilometers or more within an acceptable time schedule.


The gas-insulated transmission line (GIL) is a system for the transmission of electricity at high power ratings over long distances. In cases where overhead lines are not possible, the GIL is a viable technical solution to bring the power transmitted by an overhead line underground without a reduction of power transmission capacity.

As a gas-insulated system, the GIL has the advantage of electrical behavior similar to that of an overhead line, which is important to the operation of the complete network. Because of the large cross section of the conductor, the GIL has low electrical losses compared with other transmission systems (overhead lines and cables).

This reduces the operating and transmission costs, and it contributes to reduction of global warming because less power needs to be generated.

Safety of personnel in the vicinity of a GIL is very high because the solid metallic enclosure provides reliable protection. Even in the rare case of an internal failure, the metallic enclosure is strong enough to withstand damage.

This allows the use of GILs in street and railway tunnels and under bridges with public traffic. No flammable materials are used to build a GIL.

The use of GILs in traffic tunnels makes the tunnels more economical and can solve some environmental problems. If GIL is added to a traffic tunnel, the costcan be shared between the electric power supply company and the owner of the traffic part (train, vehicles).

The environmental advantage is that no additional overhead line needs to be built parallel to the tunnel. Because of the low capacitive load of the GIL, long lengths of 100 km and more can be built. Where overhead lines are not suitable due to environmental factors or where they would spoil a particular landscape, the GIL is a viable alternative because it is invisible and does not disturb the landscape. The

GIL consists of three single-phase encapsulated aluminum tubes that can be directly buried in the ground or laid in a tunnel. The outer aluminum enclosure is at ground potential. The interior, the annular space between the conductor pipe and the enclosure, is filled with a mixture of gas, mainly nitrogen (80%) with some SF6 (20%) to provide electrical insulation.

A reverse current, more than 99% of the conductor current value, is induced in the enclosure. Because of this reverse current, the outer magnetic field is very low.

GIL combines reliability with high transmission capacity, low losses, and low emission of magnetic fields. Because it is laid in the ground, GIL also satisfies the requirements for power transmission lines without any visual impact on the environment or the landscape.

Of course, the system can also be used to supply power to meet the high energy demands of conurbations and their surroundings. The directly buried GIL combines the advantage of underground laying with a transmission capacity equivalent to that of an overhead power line [1–3].


There are usually many factors that impact on the selection of the structure type for use in an OHTL. Some of the more significant are briefly identified below.

Erection Technique: It is obvious that different structure types require different erection techniques. As an example, steel lattice towers consist of hundreds of individual members that must be bolted together, assembled, and erected onto the four previously installed foundations.

A tapered steel pole, on the other hand, is likely to be produced in a single piece and erected directly on its previously installed foundation in one hoist. The lattice tower requires a large amount of labor to accomplish the considerable number of bolted joints, whereas the pole requires the installation of a few nuts applied to the foundation anchor bolts plus a few to install the crossarms.

The steel pole requires a large-capacity crane with a high reach which would probably not be needed for the tower. Therefore, labor needs to be balanced against the need for large, special equipment and the site’s accessibility for such equipment.

Public Concerns: Probably the most difficult factors to deal with arise as a result of the concerns of the general public living, working, or coming in proximity to the line. It is common practice to hold public hearings as part of the approval process for a new line.

Such public hearings offer a platform for neighbors to express individual concerns that generally must be satisfactorily addressed before the required permit will be issued. A few comments demonstrate this problem.

The general public usually perceives transmission structures as ‘‘eyesores’’ and distractions in the local landscape. To combat this, an industry study was made in the late 1960s (Dreyfuss, 1968) sponsored by the Edison Electric Institute and accomplished by Henry Dreyfuss, the internationally recognized industrial designer.

While the guidelines did not overcome all the objections, they did provide a means of satisfying certain very highly controversial installations (Pohlman and Harris, 1971). Parents of small children and safety engineers often raise the issue of lattice masts, towers, and guys, constituting an ‘‘attractive challenge’’ to determined climbers, particularly youngsters.

Inspection, Assessment, and Maintenance: Depending on the owning utility, it is likely their in-house practices will influence the selection of the structure type for use in a specific line location. Inspections and assessment are usually made by human inspectors who use diagnostic technologies to augment their personal senses of sight and touch.

The nature and location of the symptoms of critical interest are such that they can be most effectively examined from specific perspectives. Inspectors must work from the most advantageous location when making inspections.

Methods can include observations from ground or fly-by patrol, climbing, bucket trucks, or helicopters. Likewise, there are certain maintenance activities that are known or believed to be required for particular structure types.

The equipment necessary to maintain the structure should be taken into consideration during the structure type selection process to assure there will be no unexpected conflict between maintenance needs and r-o-w restrictions.

Future Upgrading or Uprating: Because of the difficulty of procuring r-o-w’s and obtaining the necessary permits to build new lines, many utilities improve their future options by selecting structure types for current line projects that will permit future upgrading and=or uprating initiatives.


Impact of corona discharges on the design of high-voltage lines has been recognized since the early days of electric power transmission when the corona losses were the limiting factor. Even today, corona losses remain critical for HV lines below 300 kV.

With the development of EHV lines operating at voltages between 300 and 800 kV, electromagnetic interferences become the designing parameters. For UHV lines operating at voltages above 800 kV, the audible noise appears to gain in importance over the other two parameters.

The physical mechanisms of these effects—corona losses, electromagnetic interference, and audible noise—and their current evaluation methods are discussed below.

Corona Losses
The movement of ions of both polarities generated by corona discharges, and subjected to the applied field around the line conductors, is the main source of energy loss. For AC lines, the movement of the ion space charges is limited to the immediate vicinity of the line conductors, corresponding to their maximum displacement during one half-cycle, typically a few tens of centimeters, before the voltage
changes polarity and reverses the ionic movement.

For direct current (DC) lines, the ion displacement covers the whole distance separating the line conductors, and between the conductors and the ground. Corona losses are generally described in terms of the energy losses per kilometer of the line.

They are generally negligible under fair-weather conditions but can reach values of several hundreds of kilowatts per kilometer of line during foul weather. Direct measurement of corona losses is relatively complex, but foul-weather losses can be readily evaluated in test cages under artificial rain conditions, which yield the highest energy loss.

The results are expressed in terms of the generated loss W, a characteristic of the conductor to produce corona losses under given operating conditions.

Electromagnetic Interference
Electromagnetic interference is associated with streamer discharges that inject current pulses into the conductor. These pulses of steep front and short duration have a high harmonic content, reaching the
tens of megahertz range. A tremendous research effort was devoted to the subject during the years 1950–1980 in an effort to evaluate the electromagnetic interference from HV lines.

The most comprehensive contributions were made by Moreau and Gary (1972a,b) of E ´ lectricite´ de France, who introduced the concept of the excitation function, G(v), which characterizes the ability of a line conductor to generate electromagnetic interference under the given operating conditions.


The onset of important power system problems can be assessed in part by experience from contemporary geomagnetic storms. At geomagnetic field disturbance levels as low as 60–100 nT=min (a measure of the rate of change in the magnetic field flux density over the Earth’s surface), power system operators have noted system upset events such as relay misoperation, the offline tripping of key assets, and even high levels of transformer internal heating due to stray flux in the transformer from GIC-caused half-cycle saturation of the transformer magnetic core.

Reports of equipment damage have also included large electric generators and capacitor banks. Power networks are operated using what is termed as ‘‘N– 1’’ operation criterion. That is, the system must always be operated to withstand the next credible disturbance contingency without causing a cascading collapse of the system as a whole.

This criterion normally works very well for the well-understood terrestrial environment challenges, which usually propagate more slowly and are more geographically confined. When a routine weather-related single-point failure occurs, the system needs to be rapidly adjusted (requirements typically allow a 10–30 min response time after the first incident) and positioned to survive the next possible contingency.

Geomagnetic field disturbances during a severe storm can have a sudden onset and cover large geographic regions. Geomagnetic field disturbances can therefore cause near-simultaneous, correlated, multipoint failures in power system infrastructures, allowing little or no time for meaningful human interventions that are intended within the framework of the N– 1 criterion.

This is the situation that triggered the collapse of the Hydro Quebec power grid on March 13, 1989, when their system went from normal conditions to a situation where they sustained seven contingencies (i.e., N– 7) in an elapsed time of 57 s; the province-wide blackout rapidly followed with a total elapsed time of 92 s from normal conditions to a complete collapse of the grid.

For perspective, this occurred at a disturbance intensity of approximately 480 nT=min over the region. A recent examination by Metatech of historically large disturbance intensities indicated that disturbance levels greater than 2000 nT=min have been observed even in contemporary storms on at least three occasions over the last 30 years at geomagnetic latitudes of concern for the North American power grid infrastructure and most other similar world locations: August 1972, July 1982, and March 1989.

Anecdotal information from older storms suggests that disturbance levels may have reached nearly 5000 nT=min, a level #10 times greater than the environment which triggered the Hydro Quebec collapse (Kappenman, 2005). Both observations and simulations indicate that as the intensity of the disturbance increases, the relative levels of GICs and related power system impacts will also proportionately increase.

Under these scenarios, the scale and speed of problems that could occur on exposed power grids has the potential to cause widespread and severe disruption of bulk power system operations. Therefore, as storm environments reach higher intensity levels, it becomes more likely that these events will precipitate widespread blackouts to exposed power grid infrastructures.


As the load varies in a distribution system, a variable voltage drop will occur in the system impedance, which is mainly reactive. Assuming the generator voltage remains constant, the voltage at the load bus will vary.

The voltage drop is a function of the reactive component of the load current, and system and transformer reactance. When the loads change very rapidly, or fluctuate frequently, it may cause ‘‘voltage flicker’’ at the customers’ loads.

Voltage flicker can be annoying and irritating to customers because of the ‘‘lamp flicker’’ it causes. Some loads can also be sensitive to these rapid voltage fluctuations.

An SVC can compensate voltage drop for load variations and maintain constant voltage by controlling the duration of current flow in each cycle through the reactor. Current flow in the reactor can be controlled by controlling the gating of thyristors that control the conduction period of the thyristor in each cycle, from zero conduction (gate signal off) to full-cycle conduction.

In Fig. 18.2a, for example, assume the MVA of the fixed capacitor bank is equal to the MVA of the reactor when the reactor branch is conducting for full cycle. Hence, when the reactor branch is conducting full cycle, the net reactive power drawn by the SVC (combination of capacitor bank and thyristor controlled reactor) will be zero.

When the load reactive power (which is usually inductive) varies, the SVC reactive power will be varied to match the load reactive power by controlling the duration of the conduction of current in the thyristor controlled reactive power branch.
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