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 GAS 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 accessories
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


A deliberate and complete installation plan, including the future addition of similar equipment, is essential so that all aspects of construction can be reviewed.

The preassembled sections of the equipment and the manufacturer’s instructions dictate the assembly sequence and, in most instances, follow a series of steps categorized as follows:

a) Preconstruction meeting between the user and the manufacturer
b) Site preparation including grading; installation of drainage, foundations, and grounding mats; access roads; and auxiliary power
c) Staging of construction equipment required during the installation
d) Final alignment and leveling of foundation supports
e) Receiving, unloading, and storing GIS equipment
f) On-site assembly
g) Leak testing
h) Connection of control wires
i) Purging and filling with insulating gas
j) Mechanical or operational testing
k) Dielectric testing
l) Cleanup in accordance with applicable regulations
m) Energization

Other planning considerations are as follows:

- A schedule for work crews should be prepared to provide for more economical use of manpower and to minimize conflicts caused by limited space. Scheduling may also result in the release of specialized skills in the shortest possible time.

- On-site or nearby preassembly areas should be planned when practical so that specialized equipment can be set up and repetitive assembly tasks can be performed under controlled conditions.

- A site layout designating erection equipment locations should be prepared to allow maximum use of the equipment with minimum movement. The layout should include details for each phase of installation so that orderly movement of the equipment can be maintained.

- The capacity of cranes, hoists, gas-handling equipment, welding equipment, etc., should be considered to ensure that the proper size equipment is available for the job.

- Electric power, heat, water, etc., should be available at the appropriate time in the installation sequence.

- The suitability of the site for each phase of construction and installation should be planned in advance (e.g., to move about the work area requires proper ground preparation).

- Cleanliness, in accordance with manufacturer’s instructions, should be observed at all times.

- Material safety data sheets and other health and safety information should be readily available to the work crews.


PD measurements are an ideal method for evaluating switchgear apparatus with non-self-restoring insulation. During a temporary overvoltage, during a high-voltage test, or under transient voltage conditions during operation, PDs may occur on insulation of this type, which includes gas, liquid, and solid materials.

If these PDs are sustained due to poor materials, design, and/or foreign inclusions in the insulation, degradation and possible failure of the insulation structure may occur.

Due to the variability of performance of dielectric materials and system designs, it is recommended that partial discharge tests be made as design tests in conjunction with the other dielectric tests on new switchgear equipment designs.

The partial discharge test should be performed both before and after the impulse and normal frequency dielectric tests. Once performance is established, partial discharge tests on the switchgear equipment design need only be performed following the normal frequency withstand tests.

Due to the possible influence that the impulse and normal frequency dielectric tests may have on the outcome of the partial discharge test, the partial discharge test may be performed a substantial time after these dielectric tests.

In some cases, the partial discharge test can be made as a part of the normal frequency withstand test. The following procedure is recommended for PD tests on switchgear equipment. The normal frequency voltage is applied and raised to the dry normal frequency withstand voltage level, as specified by standards, for no less than 10 s.

Partial discharges may occur at this test voltage depending on the PD voltage inception level of the equipment under test. The voltage is then decreased to the partial discharge test voltage level as specified by the equipment standard and held at that voltage for one minute.

If the measured PD level exceeds the level allowed by the equipment standard at the end of this time limit, the equipment is considered to have failed this test. A PD level lower than that allowed by the equipment standard signifies that the apparatus has passed.

Partial discharge acceptance levels and related normal frequency test voltages are not listed in this guide because the various switchgear equipment standards list the specific test levels established for that equipment.

Until the individual PD acceptance levels and test voltages are established by standards, the responsibility rests with the manufacturer for meeting the technical requirements for the specific equipment, in agreement with the user.


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.


High-voltage and extra-high-voltage (EHV) transmission lines interconnect power plants and loads, and form an electric network. This system contains 500-kV, 345-kV, 230-kV, and 115-kV lines. T

Presently, synchronous ties (AC lines) interconnect all networks in the eastern U.S. and Canada. Synchronous ties also (AC lines) interconnect all networks in the western U.S. and Canada. Several nonsynchronous ties (DC lines) connect the East and the West. These interconnections increase the reliability of the electric supply systems.

In the U.S., the nominal voltage of the high-voltage lines is between 100 kV and 230 kV. The voltage of the extra-high-voltage lines is above 230 kV and below 800 kV.

The voltage of an ultra-high-voltage line is above 800 kV. The maximum length of high-voltage lines is around 200 miles.

Extra-high-voltage transmission lines generally supply energy up to 400–500 miles without intermediate switching and var support. Transmission lines are terminated at the bus of a substation.

The physical arrangement of most extra-high-voltage (EHV) lines is similar. The figure below shows the major components of an EHV, which are:

1. Tower: The figure shows a lattice, steel tower.

2. Insulator: V strings hold four bundled conductors in each phase.

3. Conductor: Each conductor is stranded, steel reinforced aluminum cable.

4. Foundation and grounding: Steel-reinforced concrete foundation and grounding electrodes placed in the ground.

5. Shield conductors: Two grounded shield conductors protect the phase conductors from lightning.

At lower voltages the appearance of lines can be improved by using more aesthetically pleasing steel tubular towers. Steel tubular towers are made out of a tapered steel tube equipped with banded arms.

The arms hold the insulators and the conductors. Figure 4.6 shows typical 230-kV steel tubular and lattice double-circuit towers.


The figure below shows the concept of typical energy transmission and distribution systems. The generating station produces the electric energy. The generator voltage is around 15 to 25 kV. This relatively low voltage is not appropriate for the transmission of energy over long distances.

At the generating station a transformer is used to increase the voltage and reduce the current. In Fig. 4.3 the voltage is increased to 500 kV and an extra-high-voltage (EHV) line transmits the generator-produced energy to a distant substation.

Such substations are located on the outskirts of large cities or in the center of several large loads. As an example, in Arizona, a 500-kV transmission line connects the Palo Verde Nuclear Station to the Kyrene and Westwing substations, which supply a large part of the city of Phoenix.

The voltage is reduced at the 500 kV/220 kV EHV substation to the high-voltage level and high voltage
lines transmit the energy to high-voltage substations located within cities.

At the high-voltage substation the voltage is reduced to 69 kV. Sub-transmission lines connect the high-voltage substation to many local distribution stations located within cities. Sub-transmission lines are frequently located along major streets.

The voltage is reduced to 12 kV at the distribution substation. Several distribution lines emanate from each distribution substation as overhead or underground lines.
Distribution lines distribute the energy along streets and alleys. Each line supplies several step-down transformers distributed along the line.

The distribution transformer reduces the voltage to 230/115 V, which supplies houses, shopping centers, and other local loads. The large industrial plants and factories are supplied directly by a subtransmission line or a dedicated distribution line as shown in the figure.

The overhead transmission lines are used in open areas such as interconnections between cities or along wide roads within the city. In congested areas within cities, underground cables are used for electric energy transmission.

The underground transmission system is environmentally preferable but has a significantly higher cost. In the figure the 12-kV line is connected to a 12-kV cable which supplies commercial or industrial customers.

The figure also shows 12-kV cable networks supplying downtown areas in a large city. Most newly developed residential areas are supplied by 12-kV cables through pad-mounted step-down transformers as shown in the figure.


The excitation system provides the DC voltage to the field winding of the generator and modulates this voltage for control purposes. There are many different configurations and designs of excitation systems.

Stability programs usually include a variety of models capable of representing most systems. These models normally include the IEEE standard excitation system models, described in IEEE Standard 421.5 (1992).

Reference should be made to that document for a description of the various models and typical data for commonly used excitation system designs. The excitation system consists of several subsystems, as shown in Fig. 11.33.

The excitation power source provides the DC voltage and current at the levels required by the generator field. The excitation power may be provided by a rotating exciter, either a DC generator or an AC generator (alternator) and rectifier combination, or by rectifiers supplied from the generator terminals (or other AC source).

Excitation systems with these power sources are often classified as “DC,” “AC,” and “static,” respectively. The maximum (ceiling) field voltage available from the excitation power source is an important parameter.

Depending on the type of system, this ceiling voltage may be affected by the magnitude of the field current or the generator terminal voltage, and this dependency must be modeled since these values may change significantly during a disturbance.

The automatic voltage regulator (AVR) provides for control of the terminal voltage of the generator by changing the generator field voltage. There are a variety of designs for the AVR, including various means of ensuring stable response to transient changes in terminal voltage.

The speed with which the field voltage can be changed is an important characteristic of the system. For the “DC” and most of the “AC” excitation systems, the AVR controls the field of the exciter.

Therefore, the speed of response is limited by the exciter’s time constant. The speed of response of excitation systems is characterized according to IEEE Standard 421.2 (1990).

A power system stabilizer (PSS) is frequently, but not always, included in an excitation system. It is designed to modulate the AVR input in such a manner as to contribute damping to intermachine oscillations. The input to the PSS may be generator rotor speed, electrical power, or other signals.

The PSS usually is designed with linear transfer functions whose parameters are tuned to produce positive damping for the range of oscillation frequencies of concern. It is important that reasonably correct values be used for these parameters.

The output of the PSS is limited, usually to ±5% of rated generator terminal voltage, and this limit value must be included in the model. The excitation system includes several other subsystems designed to protect the generator and excitation system from excessive duty under abnormal operating conditions.

Normally, these limiters and protective modules do not come into play for analysis of transient and oscillatory stability. However, for longer-term simulations, particularly related to voltage instability, overexcitation limiters (OEL) and under-excitation limiters (UEL) may need to be modeled. While there are many designs for these limiters, typical systems are described in IEEE Trans. (Dec. and Sept., 1995).


The implementation of “distribution automation” within the continental U.S. is as diverse and numerous as the utilities themselves. Particular strategies of implementation utilized by various utilities have depended heavily on environmental variables such as size of the utility, urbanization, and available communication paths.

The current level of interest in distribution automation is the result of:
• The maturation of technologies within the past 10 years in the areas of communication and RTUs/PLCs.

• Increased performance in host servers for the same or lower cost; lower cost of memory.

• The threat of deregulation and competition as a catalyst to automate.

• Strategic benefits to be derived (e.g., potential of reduced labor costs, better planning from better information, optimizing of capital expenditures, reduced outage time, increased customer satisfaction).

While not meant to be all-inclusive, this section on distribution automation attempts to provide some dimension to the various alternatives available to the utility engineer. The focus will be on providing insight on the elements of automation that should be included in an scalable and extensible system.

The approach will be to describe the elements of a “typical” distribution automation system in a simple
manner, offering practical observations as required.

For the electric utility, justification for automating the distribution system, while being highly desirable, was not readily attainable based on a cost/benefit ratio due to the size of the distribution infrastructure and cost of communication circuits.

Still there have been tactical applications deployed on parts of distribution systems that were enough to keep the dream alive. The development of the PC (based on the Intel architecture) and VME systems (based on the Motorola architecture) provided the first lowcost SCADA master systems that were sized appropriately for the small co-ops and municipality utilities.

New SCADA vendors then entered the market targeting solutions for small to medium-sized utilities. Eventually the SCADA vendors who had been providing transmission SCADA took notice of the distribution market.

These vendors provided host architectures based on VAX/VMS (and later Alpha/Open- VMS) platforms and on UNIX platforms from IBM and Hewlett-Packard. These systems were required for the large distribution utility (100,000–250,000 point ranges). These systems often resided on company owned LANs with communication front-end processors and user interface attached either locally on the same LAN or across a WAN.


This instrument is an extremely stable and linear integrator that integrates the voltage induced in a flux coupling coil or sensor, usually called a search coil, connected to the input terminals of the fluxmeter. The voltage, V, induced in a coil that is placed in a time varying magnetic field is V = NAdB/dt where N is the number of turns in the coil and A is the area of this coil.

This relationship can be rewritten to yield òVdt = NA(DB). From this equation it can be seen that the time integral of the voltage induced in the coil is proportional to the change in B at its location. The leads from the flux coupling coil should be twisted to eliminate the effect of stray magnetic flux linking these leads and producing errors.

The plane of the coil should be positioned to obtain the maximum reading, which yields the correct value. Because a fluxmeter measures the change in B, one way that a dc measurement can be made is by turning on and off the magnetic device under test, which causes B to go from approximately zero to its operating level.

If the fluxmeter is zeroed when the power to the magnetic device is off, then the instrument will indicate the operating level of B when power is applied. Whenever possible, the accuracy of measuring B can be improved by reversing the applied voltage on the device under test which causes the change of B to be twice the operating level of B.

Reversing the applied voltage and measuring the change in B from full voltage of one polarity to full voltage of the reverse polarity eliminates the effects of residual magnetism. Another technique is to zero the fluxmeter while the search coil is in a zero magnetic field and then place the search coil in the magnetic field to be measured.

When it is used to measure the flux produced by ac systems, the search coil is kept stationary after positioning it to obtain the maximum reading. If the device under test is of the permanent magnet type, it may not be possible to turn it off.

Then a change in B through the search coil can only be accomplished by zeroing the fluxmeter when the coil is not in the vicinity of the device and then placing the coil where the measurement of B is wanted.

The resulting change in B passing through the coil, which is indicated by the fluxmeter, is the measured B. The fluxmeter controls are organized so as to display the average flux density across the area of the coil or the total flux within the coil. Input dials provide for setting in the area-turns of the coil or only the number of turns.

The indicating meters have either analog or digital displays with readings in the cgs system. An output signal from zero to one volt proportional to the meter readings is also available.

These instruments have ranges from 104 to 109 Mx turns with accuracies as great as 1/4% for dc measurements. They will respond to input pulses with rise or fall times (10–90%) as fast as 10 ms.

Uncompensated thermocouple voltages, which are usually present at the instrument’s input, are removed by adjusting a zero control for minimum drift of the integrator. The resulting drift can be as low as 100 Mx turns per minute.

For ac fields these instruments will yield rms values of B for frequencies from 10 Hz to 100 kHz with accuracies as high as 1/2 of full scale. These instruments can operate from a 50/60 Hz ac power line or internal batteries.


Preservative Treatment. Pole decay is due to a fungus which requires air, moisture, warmth, and food for its subsistence; the wood of the pole constitutes its food. The conditions most favorable to the growth of the fungus are found at the ground line.

The preservative has toxic or antiseptic properties which make the wood either poisonous or unfit food for the fungus. Preservatives and preserving methods conforming to the standards of the American Wood Preservers Association (AWPA)85 should be used in the treatment of poles.

There are many wood preservatives, including those using poisonous salts such as copper, mercury, zinc, and arsenic compounds. However, only two are included in AWPA recommendations for poles, Standard C-4-74-C:

1. Coal-tar creosote, AWPA Standard P1-65
2. A 5% solution of pentachlorophenol in a petroleum distillate, AWPA Standard P8 (commonly called “penta”)

By AWPA Standard M1-70, pentachlorophenol is not recommended for use in coastal waters. Coastal waters are defined as salty waters. One other preservative is increasing in popularity.

This is AWPA Standard P11-70, a creosote-pentachlorophenol mixture in which pentachlorophenol is not less than 2% of the mixture. All of these preservatives are applied by the following methods:

1. The open-tank method, applied to cedar poles, consists in boiling the butts of the poles in a tank of creosote oil, after which the oil is allowed to cool or the poles are transferred to a cold tank of oil. The duration of the hot and cold treatment, usually 8 h or more, depends on several factors, the most important of which is the degree of seasoning.

The treatment is based on the fact that the wood cells expand with heat and on cooling draw the creosote into the wood under atmospheric pressure. The sapwood of unseasoned poles has annular rings of a nearly impervious fiber which prevent penetration of the oil.

In seasoning, this fiber dries and breaks open. To ensure penetration of the greater part of the sapwood, which is usually less than 1 in in depth, an incision process has been developed and is almost universally used.

Narrow cuts, parallel with the wood fibers, are made to a depth of about 1/2 in at frequent intervals around the circumference of the pole for a distance above and below the ground line. Complete penetration is obtained to a depth somewhat greater than the depth of the incisions even on unseasoned poles.

2. Pressure treatment is applied to pine and fir. The poles, on a truck, are run into a steel cylinder and subjected to a steam treatment for a period of several hours at a temperature which will not damage the wood cells, usually specified at not more than 259 F (126 C).

The pressure is then removed and a vacuum applied. The steam treatment opens up the wood cells and allows the preservative to penetrate. The length of time required for the steam and vacuum treatment depends on the condition of the wood, the amount of oil that is to be injected, and the depth of penetration desired.

From this point in the process, one of two methods may be followed. The full-cell, or Bethel, process allows all the preservative injected to remain in the wood. This process is generally used for piling and underwater work when it is desired to exclude water from the wood and to resist the attack of marine borers.

The empty-cell process draws off excess oil and secures protection from decay by the coating of oil left on the walls of the wood cells. The empty-cell process is adequate and preferable for usual structures and is used almost exclusively for poles and arms.

The empty-cell treatment is obtained by either the Rueping or the Lowry process. The Rueping process seems to be in more general use, although the Lowry process is equally successful.

In the Rueping process, following the steam treatment, an air pressure is applied. While still under pressure, hot oil is forced into the cylinder. The oil is held under this pressure and maintained at a temperature of about 200 F (93.5 C) by steam coils within the cylinder, for a period of several hours.

Upon removing the oil and reducing the pressure, the compressed air within the wood cells forces out the surplus oil. The amount of oil retained depends on the pressures applied and the time of treatment, although it is possible to remove only a part of the oil that has been injected.

The Lowry process is similar to the Rueping process except that no compressed air is used. After the preservative has been forced into the wood under pressure, a high vacuum is quickly created, causing a sudden expansion of the air within the wood cells and thus driving out surplus preservative.


Creep is Permanent Elongation at Everyday Tensions. Conductors permanently elongate under tension even if the tension level never exceeds everyday levels.

This permanent elongation caused by everyday tension levels is called creep. Creep can be determined by long-term laboratory creep tests.

The results of the tests are used to generate creep-versus-time curves. On the stress-strain graphs, creep curves are often shown for 6-month, 1-year, and 10-year periods.

Figure 14-27 shows these typical creep curves for a 37-strand 250- to 1033.5-kcmil AAC. In Fig. 14-27, assume that the conductor tension remains constant at the initial stress of 4450 lb/in2.

At the intersection of this stress level and the initial elongation curve, 6-month, 1-year, and 10-year creep curves, the conductor elongation from the initial elongation of 0.062% increases to 0.11%, 0.12%, and 0.15%, respectively. Because of creep elongation, the resulting final sags are greater and the conductor tension is less than the initial values.

Creep elongation in aluminum conductors is quite predictable as a function of time and obeys a simple exponential relationship. Thus, the permanent elongation due to creep at everyday tension can be found for any period of time after initial installation.

Creep elongation of copper and steel strands is much less and is normally ignored. Permanent increase in conductor length due to heavy load occurrences cannot be predicted at the time a line is built.

The reason for this unpredictability is that the occurrence of heavy ice and wind loads is random. A heavy ice storm may occur the day after the line is built or may never occur over the life of the line.


Blondel’s theorem of polyphase metering describes the measurement of power in a polyphase system made up of an arbitrary number of conductors.

The theorem provides the basis for correctly metering power in polyphase circuits. In simple terms, Blondel’s theorem states that the total power in a system of (N) conductors can be properly measured by using (N) wattmeters or watt-measuring elements.

The elements are placed such that one current coil is in each of the conductors and one potential coil is connected between each of the conductors and some common point.

If this common point is chosen to be one of the (N) conductors, there will be zero voltage across one of the measuring element potential coils. This element will register zero power.

Therefore, the total power is correctly measured by the remaining (N – 1) elements.

In application, this means that to accurately measure the power in a four-wire three-phase circuit (N = 4), the meter must contain (N – 1) or three measuring elements. Likewise, for a three-wire three-phase circuit (N = 3), the meter must contain two measuring elements.

There are meter designs available that, for commercial reasons, employ less than the minimum number of elements (N – 1) for a given circuit configuration. These designs depend on balanced phase voltages for proper operation.
Their accuracy suffers as voltages become unbalanced.


The electromechanical watthour meter is basically a very specialized electric motor, consisting of
• A stator and a rotor that together produce torque
• A brake that creates a counter torque
• A register to count and display the revolutions of the rotor

Single Stator Electromechanical Meter
A two-wire single stator meter is the simplest electromechanical meter. The single stator consists of two electromagnets.

One electromagnet is the potential coil connected between the two circuit conductors. The other electromagnet is the current coil connected in series with the load current.

Figure 7.1 shows the major components of a single stator meter.

The electromagnetic fields of the current coil and the potential coil interact to generate torque on the rotor of the meter. This torque is proportional to the product of the source voltage, the line current, and the cosine of the phase angle between the two. Thus, the torque is also proportional to the power in the metered circuit.

The device described so far is incomplete. In measuring a steady power in a circuit, this meter would generate constant torque causing steady acceleration of the rotor. The rotor would spin faster and faster until the torque could no longer overcome friction and other forces acting on the rotor.

This ultimate speed would not represent the level of power present in the metered circuit. To address these problems, designers add a permanent magnet whose magnetic field acts on the rotor.

This field interacts with the rotor to cause a counter torque proportional to the speed of the rotor. Careful design and adjustment of the magnet strength yields a meter that rotates at a speed proportional to power.

This speed can be kept relatively slow. The product of the rotor speed and time is revolutions of the rotor. The revolutions are proportional to energy consumed in the metered circuit.

One revolution of the rotor represents a fixed number of watthours. The revolutions are easily converted via mechanical gearing or other methods into a display of watthours or, more commonly, kilowatthours.


Distance relays respond to the voltage and current, i.e., the impedance, at the relay location. The impedance per mile is fairly constant so these relays respond to the distance between the relay location and the fault location.

As the power systems become more complex and the fault current varies with changes in generation and system configuration, directional overcurrent relays become difficult to apply and to set for all contingencies, whereas the distance relay setting is constant for a wide variety of changes external to the protected line.

There are three general distance relay types as shown in Fig. 9.32. Each is distinguished by its application and its operating characteristic.

Impedance Relay
The impedance relay has a circular characteristic centered at the origin of the R-X diagram. It is nondirectional and is used primarily as a fault detector.

Admittance Relay
The admittance relay is the most commonly used distance relay. It is the tripping relay in pilot schemes and as the backup relay in step distance schemes. Its characteristic passes through the origin of the R-X diagram and is therefore directional.

In the electromechanical design it is circular, and in the solid state design, it can be shaped to correspond to the transmission line impedance.

Reactance Relay
The reactance relay is a straight-line characteristic that responds only to the reactance of the protected line. It is nondirectional and is used to supplement the admittance relay as a tripping relay to make the overall protection independent of resistance.

It is particularly useful on short lines where the fault arc resistance is the same order of magnitude as the line length. Figure 9.33 shows a three-zone step distance relaying scheme that provides instantaneous protection over 80–90% of the protected line section (Zone 1) and time-delayed protection over the remainder of the line (Zone 2) plus backup protection over the adjacent line section. Zone 3 also provides backup protection for adjacent lines sections.

In a three-phase power system, 10 types of faults are possible: three single phase-to-ground, three phase-to-phase, three double phase-to-ground, and one three-phase fault. It is essential that the relays provided have the same setting regardless of the type of fault.

This is possible if the relays are connected to respond to delta voltages and currents. The delta quantities are defined as the difference between any two phase quantities, for example, Ea – Eb is the delta quantity between phases a and b.

In general, for a multiphase fault between phases x and y,

Ex-Ey/ Ix-Iy  = IZ

where x and y can be a, b, or c and Z1 is the positive sequence impedance between the relay location and the fault. For ground distance relays, the faulted phase voltage, and a compensated faulted phase current must be used.

Ex / ( Ix+mI0) = Z1

where m is a constant depending on the line impedances, and I0 is the zero sequence current in the
transmission line. A full complement of relays consists of three phase distance relays and three ground
distance relays. This is the preferred protective scheme for high voltage and extra high voltage systems.

Pilot Protection
As can be seen from Fig. 9.33, step distance protection does not offer instantaneous clearing of faults over 100% of the line segment. In most cases this is unacceptable due to system stability considerations. To cover the 10–20% of the line not covered by Zone 1, the information regarding the location of the fault is transmitted from each terminal to the other terminal(s).

A communication channel is used for this transmission. These pilot channels can be over power line carrier, microwave, fiberoptic, or wire pilot. Although the underlying principles are the same regardless of the pilot channel, there are specific design details that are imposed by this choice.

Power line carrier uses the protected line itself as the channel, superimposing a high frequency signal on top of the 60 Hz power frequency. Since the line being protected is also the medium used to actuate the protective devices, a blocking signal is used.

This means that a trip will occur at both ends of the line unless a signal is received from the remote end.

Microwave or fiberoptic channels are independent of the transmission line being protected so a tripping signal can be used.

Wire pilot channels are limited by the impedance of the copper wire and are used at lower voltages where the distance between the terminals is not great, usually less than 10 miles.

Directional Comparison
The most common pilot relaying scheme in the U.S. is the directional comparison blocking scheme, using power line carrier. The fundamental principle upon which this scheme is based utilizes the fact that, at a given terminal, the direction of a fault either forward or backward is easily determined by a directional relay.

By transmitting this information to the remote end, and by applying appropriate logic, both ends can determine whether a fault is within the protected line or external to it. Since the power line itself is used as the communication medium, a blocking signal is used.

Transfer Tripping
If the communication channel is independent of the power line, a tripping scheme is a viable protection scheme. Using the same directional relay logic to determine the location of a fault, a tripping signal is sent to the remote end.

To increase security, there are several variations possible. A direct tripping signal can be sent, or additional underreaching or overreaching directional relays can be used to supervise the tripping function and increase security.

An underreaching relay sees less than 100% of the protected line, i.e., Zone 1. An overreaching relay sees beyond the protected line such as Zone 2 or 3.

Phase Comparison
Phase comparison is a differential scheme that compares the phase angle between the currents at the ends of the line. If the currents are essentially in phase, there is no fault in the protected section.

If these currents are essentially 180o out of phase, there is a fault within the line section. Any communication link can be used.

Pilot Wire
Pilot wire relaying is a form of differential line protection similar to phase comparison, except that the phase currents are compared over a pair of metallic wires.

The pilot channel is often a rented circuit from the local telephone company.

However, as the telephone companies are replacing their wired facilities with microwave or fiberoptics, this protection must be closely monitored.


The ability of a pole to be self-supporting depends on the class of the pole and the load it must carry (ignoring for the present the characteristic of the soil).

Classes of Poles
All wood poles are divided into classes based on thickness and circumference. One system uses five classes: 5, 4, 2, 0, and 00, ranging from moderately thin (class 5) to extra heavy (class 00). Knowing the load, it is possible then to select the proper class of pole for each location and degree of loading.

If the number of units of loading is greater than the number of units the pole can support by itself, either the pole must be guyed or the conductors slackened to reduce the tension.

Heavier-class Poles
Poles one class heavier than the class specified by the tables should be used for each of the following purposes:

1. Junction poles

2. Poles supporting alley or side arms

3. Poles supporting line disconnects (except in-line types) or fuse cutouts

In addition, a pole of at least class 4 should be specified for deadend poles, angle poles, and transformer (or capacitor, regulator, or other equipment) poles.

Extra Heavy-class Poles
Class 0 and class 00 poles are special oversize poles and are used primarily in the following situations:

1. In place of sidewalk guys, the most expensive guys to install

2. At an angle in the line in place of the combination of a span guy with a stub pole and sidewalk guy on the opposite side of the road

3. At T intersections, where normally a sidewalk guy or a span guy with a stub pole would be used

4. Where guying permission or rights cannot be obtained

5. To satisfy consumer complaints, by replacing an existing or proposed anchor guy.

Selecting the Guy Wire
When the loading exceeds the strength of a pole, the pole should be guyed. The physical location of the pole in the field will determine what type of guy should be used: anchor, span, head, or sidewalk type.

Guy protectors should be installed on all anchor guys accessible to the public. When a pole line changes direction and the turn angle is less than 60°, the corner, or “pivot,” pole may be guyed with a single guy bisecting the angle. At angles greater than 60°, the pole should be guyed against the stress in each direction.

Selecting the Anchor
Anchors come in many types and sizes, each designed for certain soil and guying conditions. While each will do its specific job better than another design of anchor, most find use under more than one set of conditions.


Connections made between conductors, in joining two ends together or in making a tap off the other, should be electrically and mechanically sound. They not only should introduce no additional resistance (and associated heating) at the points of contact, but they should also not be subject to corrosion or conductor stresses or movements.

In earlier times, such connections usually consisted of wires wrapped together and soldered. Later, twisted sleeves were employed in which the two ends of the conductor were inserted in a sleeve and the whole assembly twisted.

Stranded conductors had each strand serviced separately before soldering. Many of these connections still exist.

The later development of “solderless” or mechanical connectors made obsolete the wrapped and soldered splices. Parallel-groove clamps, split-bolt connectors, and crimped sleeves made splicing more simple and more uniform, with substantial reduction in labor costs.

Some of these are shown in Figure 9-1.

For rapid installation, usually during periods of emergency, the “automatic” splice, employing wedges which, under pressure of the sagging wire, grip the ends of the conductors to be spliced, was also developed; this is relatively more expensive.

When necessary, friction tape, or insulating tape covered with friction tape, is employed to continue the covering or insulation. In present day applications, the splices are often left bare.

In many instances, where it is desirable to disconnect the connection readily, special clamps, sometimes known as “live-line” or “hotline” clamps, are used; these are shown in Figure 9-2.

The advent of aluminum conductors into a field in which the conductors previously were exclusively copper presents problems where conductors of dissimilar metals need to be connected together.

Special care is exercised, since the connection may be affected by chemical interaction between the two metals, especially when wet and in the presence of some pollutants; but even more, because of the different rates of expansion when heated.

The uneven expansion and contraction will eventually cause such splices to become loose, and their resistance to increase with consequent abnormal heating, with possible dire results.

Connectors for copper-to-copper conductors are usually made of copper, though bronze is sometimes used for greater strength. Where aluminum or ACSR conductors are to be connected to similar conductors, connectors of aluminum are used.

Where the conductors to be connected are of dissimilar metals, connectors are so designed that only surfaces of similar metals come in contact with each other; aluminum clamps with copper bushings, or vice versa, are employed for this purpose. Care is taken to prevent water dripping from copper items, which may contain copper salts, from coming into contact with aluminum items.

While this discussion applies equally to overhead and underground installations, it must be noted that splices on underground cables, especially where lead-sheath cables are involved, are very much more complex. The connector must be smooth so that no corona discharge will pit the metals.

The insulation covering the connector is carried over from one cable to the other by means of insulating tapes wound about the connector.

The lead sheath is sweated or soldered to the cable sheaths and is usually larger in diameter. The splice may be filled with an insulating compound, which is heated and poured into the splice, where it hardens on cooling.

The new plastic-insulated cables are spliced with a connector between the two conductors and plastic tape of the same material as the insulation wrapped about the assembly; the tape tends to become homogeneous with time.


Since it is impractical to manufacture an infinite number of wire sizes, standards have been adopted for an orderly and simple arrangement of such sizes for manufacturers and users. The American Wire
Gauge (AWG), formerly known as the Browne and Sharpe Gauge (B&S), is the standard generally employed in this country and where American practices prevail.

In defining conductor sizes, the circular mil (cmil) is usually used as the unit of measurement. It is the area of a circle having a diameter of 0.001 in, which works out to be 0.7854 × 10–6 in2. In the metric system, these figures are a diameter of 0.0254 mm and an area of 506.71 × 10–6 mm2.

Wire sizes are given in gauge numbers, which, for distribution system purposes, range from a minimum of no. 12 to a maximum of no. 0000 (or 4/0) for solid-type conductors. Solid wire is not usually made in sizes larger than 4/0, and stranded wire for sizes larger than no. 2 is generally used.

Above the 4/0 size, conductors are generally given in circular mils (cmil) or in thousands of circular mils (cmil × 103); stranded conductors for distribution purposes usually range from a minimum of no. 6 to a maximum of 1,000,000 cmil (or 1000 cmil × 103) and may consist of two classes of strandings.

These wire sizes and their dimensions are given in Table 9-2.

Gauge numbers may be determined from the formula:
Diameter, in = ———
Cross-sectional area, cmil = ————
where n is the gauge number (no. 0 = 0; no. 00 = – 1; no. 000 = – 2; no. 0000 = – 3).

It will be noted that the diameter of the wire doubles approximately every sixth size (e.g., no. 2 has twice the diameter of no. 8), and the cross-sectional area therefore doubles every third size and is 4 times as great every sixth size (e.g., no. 2 has twice the area of no. 5 and 4 times that of no. 8).

The diameter of stranded wire is approximately 15 percent greater than the diameter of a solid wire of the same cross-sectional area.

The gauge numbers and wire designations apply to conductors of all materials. Usually, however, the equivalent wire sizes are denoted for the several materials in comparison to copper (e.g., 4/0 aluminum is equivalent to 2/0 copper). These are indicated in the tables for such conductors.


Cross arms are the most common means of supporting distribution conductors on poles. Although they are being used less frequently, their use will persist for some time.

Standard Arms
Standard cross-section dimensions for wood cross arms (width by height) are:
3-1/4 in by 4-1/4 in
3-1/2 in by 4-1/2 in
3-3/4 in by 4-3/4 in
4 in by 5 in

Of these, the first two are most commonly used for distribution purposes, and usually only one of these will be stocked by an individual utility. The larger size finds greater use in the harsher northern and western climates, while the smaller finds use in the south and southwest.

The rectangular cross section is slightly rounded or “roofed” on the top surface to shed rain and snow.

The length of the cross arm depends on the number of conductors it is to support and the spacing between them. Standard cross arms include two-, four-, six-, and eight-pin arms, although the four- and six-pin arms, 8 ft in length, are the more widely used.

Spacing between pins for the six-pin 8-ft arm is standardized at 141 in, except for the space between the two center pins, the “climbing space” for the lineman’s safety; for primary voltages up to 15,000 V, this climbing space is 30 in, and for voltages above that value it is 36 in (with spacing between the six pins reduced to 13 in).

Spacing between pins for the four-pin 8-ft cross arm is 26 in, with a space between the two center pins of 36 in, the climbing space. See Figure 10-3. Vertical spacing between cross arms is standardized at 2 ft.

Both Douglas fir and southern yellow pine are used for cross arms because of their comparatively high bending strengths and their durability. Both are treated with preservatives after holes for pins and bolts have been bored in them.

Their insulating properties are similar to those described for wood poles.


Concrete are at present not used extensively for distribution purposes in the United States. They are, however, used extensively in Europe and other lands where woods suitable for poles are not readily or economically available.

Concrete poles are usually used where great strength and appearance are paramount requirements; concrete poles are made in several colors and finishes.

Concrete poles come in cross sections that are circular, square, or polygonal (usually six- or eight-sided). Both allow electrical risers to be installed in the hollow space within them.

Concrete poles are manufactured with hollow cores to reduce their weight, which has been (and still is) a disadvantage, especially when they are handled in the field.

 Reinforcing steel strands are installed longitudinally for the full length of the pole and prestressed before the concrete is placed;

reinforcing steel strands are also installed, essentially at right angles to the longitudinal reinforcing strands, usually as special coils wrapped around and welded to them in a manner to prevent movement during concrete casting. See Figure 10-2.

In addition to their heavier weight (compared with wood), concrete poles are relatively more expensive, another reason for their lessened usage.

All concrete poles are tapered, and the square ones have chamfered corners. All provide cable entrance openings and hand holes to permit the installation of electric riser cables in their hollow cores.

Concrete poles are not adversely affected by wet or dry rot, birds (especially woodpeckers), fire, rust, or chemicals (such as fertilizers and salt spray).

Besides being stronger and more rigid than wood, they are essentially maintenance-free; ground moisture and weather, which work against other types of poles, work in favor of concrete, hardening, toughening, and protecting its integrity.

Considering the potential lifespans, concrete claims the lowest cost per year.


Watthour meters are customarily calibrated by determining the percentage registration, that is, the percentage of the energy passed through the meter in a short time interval. This may be done by two methods:

1) By precise timing of a number of revolutions of a meter while holding the watt input constant during the period, or

2) By operating the meter for a preselected number of revolutions simultaneously with a calibrated portable watthour standard of higher accuracy than the meter.

For the first method, the watthours registered in a given time are noted while the average power is simultaneously measured during the same period with a standard wattmeter.

Since the energy represented by one revolution, or the watthour constant, has been marked on the nameplate, the watthours registered by the meter on a given period will be Kh ´ R, where Kh is the watthour constant and R is the number of revolutions.

The accuracy of the gear ratio between the rotating element and the first dial of the register can be determined by count.

The percent registration is then readily computed. Thus,

% registration = (meter watthours/ true watthours) x 100%
= [(kh x 3600 x R)/ s x W] x 100%
Kh = watthour constant
3600 = number of seconds in 1 hour
R = revolutions in the test period of s seconds
W = true average power in watts during the test period as measured with indicating instruments

The last formula is the standard formula used in testing watthour meters. The constant marked on the nameplate by some manufacturers may be other than the watthour constant.

This should always be checked before proceeding with the calibration. Very complete information regarding meter constants and other meter data, may be found in the current edition of the Electrical Metermen’s Handbook [3],7 published by the Edison Electric Institute, Washington, DC.

Additional data on testing may be found in meter manufacturers’ literature and ANSI C12.1-1988, American National Standard Code for Electricity Metering [1].


Induction-type watthour meters are basically induction motors with the following essential parts:

The rotor, which consists of an aluminum disk mounted on a shaft that is free to rotate;

The stator, which consists of voltage coil and a current coil wound on laminated iron cores;

A braking magnet, which generates a torque that opposes disk rotation; and

A revolution counter.

The voltage and current coils produce fluxes that induce eddy currents in the aluminum disk. With proper space and phase displacement the interaction between these fluxes and the eddy currents will generate a rotational torque on the disk.

The space displacement is achieved by a suitable arrangement of the coils and laminations. A 90° phase displacement is realized in part by the fact that the voltage coil is highly inductive.

The remaining phase shift is obtained by a compensating coil and resistor that is magnetically coupled to the voltage coil. Induction watthour meters are frequency dependent and may have accuracies approaching 0.1%.

Power for their operation is derived from the circuit in which they are connected. In the induction watthour meter, as the disk rotates, the flux lines generated by the permanent magnet are cut.

A voltage is generated in the disk which results in eddy current flow. The eddy currents react with the permanent magnet flux to produce a retarding torque that is proportional to the speed of the disk.

Considering these relationships, if
driving torque µ power (watts)
retarding torque µ disk speed

For steady-state conditions:
driving torque = retarding torque

Therefore: power (watts) µ disk speed and energy µ number of disk revolutions

Each disk revolution of a watthour meter represents a finite amount of energy in watthours, as defined by the value given on a meter nameplace as the disk constant, Kh.

The register on a watthour meter totals the number of revolutions the disk makes through a mechanical gear train. A register generally shows kilowatthours (kWh), with the smallest division on the units dial being 1 kWh.
free counters