Transient overvoltages can arise from a number of sources. Power disturbances result from lightning strokes or switching operations on transmission and distribution lines. Switching of power factor correction capacitors for voltage control is a major cause of switching transients.

All utility lines are designed for a certain basic insulation level (BIL) that defines the maximum surge voltage that will not damage the utility equipment but which may be passed on to the customer. Some consideration should be given to the supply system BIL in highpower electronics with direct exposure to medium-voltage utility lines.

Such information is generally available from the utility representative. The standard test waveform for establishing BIL capability is a voltage that rises to the instantaneous BIL value in 1.2 μs and decays to half that value in another 50 μs.

Other sources of transient overvoltages may lie within power electronics equipment itself. Interrupting contactor coils has already been mentioned. Diode and SCR reverse recovery current transients can also propagate within equipment.  Arcing loads may require shielding of control circuits. In general, a solid grounding system will minimize problems.

Apparatus for surge protection covers the range from the little discs in 120-V power strips for computers to the giant lightning arresters on 765-kV transmission lines. Many types now utilize the nonlinear characteristics of MOVs. These ZnO ceramic elements have a low leakage current as the applied voltage is increased until a threshold is reached at which the current will increase rapidly for higher voltages.

The operating voltage is controlled by the thickness of the ceramic disk and the processing. MOVs may be stacked in series for higher voltages and in parallel for higher currents. Lightning arresters are classified by their current rating at a given clamping voltage. Station-class arresters can handle the highest currents and are the type used by utilities on transmission and subtransmission lines.

Intermediate-class arresters have a lesser clamping ability and are used on substations and some power electronics that are directly connected to a substation. The lowest clamping currents are in distribution-class arresters that are used on distribution feeders and the smaller power electronics equipment. The cost, of course, is related to the clamping current. Arresters are rated for their clamping voltage by class and for their maximum continuous operating voltage, MCOV.

They are typically connected line-to-ground. Lightning arresters are often used to protect dry-type transformers in power electronic equipment, because such transformers may have a lower BIL rating than the supply switchgear. In 15-kV-class equipment, for example, the switchgear may be rated for 95 or 110 kV BIL, whereas the transformer may be rated for only 60 kV.

As a design rule, MOVs used for the protection of power electronics will limit peak voltage transients to 2 1/2 times their maximum continuous rated rms voltage. They may be connected either line-to-line or line-to-ground in three-phase circuits. Line-to-line connections limit switching voltage transients best but do not protect against common mode (all three lines to ground) transients.

On the other hand, the line-to-ground connection that protects against common-mode transients does not do as good a job on applied line transients. For optimum protection in equipments with exposure to severe lightning or switching transients, both may be appropriate. The volt-ampere curves for a MOV should be checked to be sure the device can sink sufficient current at the maximum tolerable circuit voltage to handle the expected transient energies.

This current will be a function of the MOV size, and a wide range of diameters is available to handle nearly any design need. Small units are supplied with wire leads, whereas the larger units are packaged in molded cases with mounting feet and screw terminals for connections.

Another device in the protection arsenal is the surge capacitor. Transient voltages with fast rise times, high dv/dt, may not distribute the voltage evenly among the turns on a transformer or motor winding. This effect arises because of the turn-to-turn and turn-to-ground capacitance distributions in the winding.

Surge capacitors can be used to slow the dv/dt and minimize the overvoltages on the winding ends. These are generally in the range of 0.5 to 1.0 μF for medium-voltage service. Some care should be exercised when these are used with SCR circuits because of the possibility of serious overvoltages from ringing. Damping resistors may be required.


As an Electrical Engineer, especially dwelling in metering theory and practice, everybody must have heard Blondel's Theorem. For starters, it says that, In a system of N conductors, N-l meter elements, properly connected, will measure the power or energy taken. The connection must be such that all voltage coils have a common tie to the conductor in which there is no current coil.

But who is the man behind the statement? He is no other than Andre Blondel, today's featured Electrical Engineering Hero.

The theory of polyphase watthour metering was first set forth on a scientific basis in 1893 by Andre E. Blondel, engineer and mathematician. His theorem applies to the measurement of real power in a polyphase system of any number of wires.

He was born on August 28, 1863 in Chaumont, Haute Marne, in France. He is a physicist, professor, and of course an engineer, a testament to his multi faceted  and talented life.

He was employed as an engineer by the Lighthouses and Beacons service after graduating first in his class at the E´cole des Ponts et Chausse´es (School of Bridges and Roadways).

Among his notable achievements and discoveries aside from the theorem named after him are as follows:

Invented the electromagnetic oscillograph, which won the grand prize at the St. Louis Exposition in 1904.

He demonstrated that there were three kinds of electric arc: the primitive, secondary arc, and a succession of oscillatory discharges.

Published a study on the coupling of synchronous generators on a large AC electric grid.

The next time you'll see an energy meter, think of the man who've contributed to what is is now today. Our Electrical Engineering Hero: Andre Blondel.


Standing waves appear when a length of line is excited at a frequency for which the electrical line length is a significant part of an electrical wavelength. They result from the constructive and destructive interference of forward and reflected waves on the line.

The behavior of the line can be determined by solving the applicable differential equations relating the line parameters to the exciting frequency. The solution of the equations for a line with losses is rather complex and adds little to the practical considerations, so the lossless line will be analyzed instead.

In the lossless line, L is the series inductance per unit length, and C is the shunt capacitance. If a differential length, dx, is considered, the inductance for that length is L dx, and the voltage in that length is e= Ldx(di/dt). Since e= (de/dx)dx, the equation can be written as dx (de/dx) = –L dx(di/dt ).

Fortunately, the computer offers an easier method of analysis by numerical integration, and line losses can be incorporated with relative ease. The difference equations can be solved by simple Euler integration, so the whole process is not nearly as daunting as in earlier years.

These equations allow numerical solutions for the voltages and currents on the line as functions of distance and time. Although it may not be immediately apparent, these difference equations, in the limit, replicate the differential equations.

the line has a surge, or characteristic, impedance defined as Z0= (L/C)^1/2 and, second, a velocity of propagation v= 1/(LC)1/2.

The characteristic impedance defines the relationship between the line and its attached load, and the velocity of propagation defines the speed of signal transmission along the line and consequently its electrical length. The electrical length of the line, in terms of wavelengths for any given exciting frequency, is ëp/ëe = v/c, where
ëp is the physical line length,
ëe is the exciting frequency wavelength in free space,
v is the velocity of propagation, and
c is the speed of light.

The parameters vary widely among the various types of transmission lines and cables typically encountered in power electronics. The overhead line has a high series inductance and relatively low shunt capacitance that leads to a high surge impedance. It also has a relatively high velocity of propagation because of the low capacitance.

In the cable, things are reversed. Shielded cable has a very high capacitance that makes the surge impedance low, and the velocity of propagation is also low. Note that the physical wavelength of a signal in such shielded cable is less than one-third of the wavelength in free space.


Through discovery, invention, and engineering application, the engineer has made electricity of continually greater use to mankind. Electrical power is the driving force to the evolution and improvement of the world.

One of the efforts and means to achieve this goal is to transmit power from the generation source to its “ load” in the most economical and feasible way. This is done via the transmission lines.

Transmission lines are essential for three purposes.

a. To transmit power from a water-power site to a market. These may he very long and justified because of the subsidy aspect connected with the project.

b. For bulk supply of power to load centers from outlying steam stations. These are likely to be relatively short.

c. For interconnection purposes, that is, for transfer of energy from one system to another in case of emergency or in response to diversity in system peaks.

Frequent attempts have been made to set up definitions of “transmission lines, ” “distribution circuits” and “substations.” none has proved entirely satisfactory or universally applicable, but for the purposes of accounting the Federal Power Commission and various state commissions have set up definitions that in essence read:

A transmission system includes all land, conversion structures and equipment at a primary source of supply; lines, switching and conversion stations between a generating or receiving point and the entrance to a distribution center or wholesale point, all lines and equipment whose primary purpose is to augment, integrate or tie together sources of power supply.


Electrical preventive maintenance should be a prime consideration for any new electrical equipment installation. Quality, installation, configuration, and application are fundamental prerequisites in attaining a satisfactory preventive maintenance program.

A system that is not adequately engineered, designed, and constructed will not provide reliable service, regardless of how good or how much preventive maintenance is accomplished.

One of the first requirements in establishing a satisfactory and effective preventive maintenance program is to have good quality electrical equipment that is properly installed. Examples of this are as follows:

a) Large exterior bolted covers on switchgear or large motor terminal compartments are not conducive to routine electrical preventive maintenance inspections, cleaning, and testing. Hinged and gasketed doors with a three-point locking system would be much more satisfactory.

b) Space heater installation in switchgear or an electric motor is a vital necessity in high humidity areas. This reduces condensation on critical insulation components. The installation of ammeters in the heater circuit is an added tool for operating or maintenance personnel to monitor their operation.

c) Motor insulation temperatures can be monitored by use of resistance temperature detectors, which provide an alarm indication at a selected temperature (depending on the insulation class). Such monitoring indicates that the motor is dirty and/or air passages are plugged.

The distribution system configuration and features should be such that maintenance work is permitted without load interruption or with only minimal loss of availability. Often, equipment preventive maintenance is not done or is deferred because load interruption is required to a critical load or to a portion of the distribution system.

This may require the installation of alternate electrical equipment and circuits to permit routine or emergency maintenance on one circuit while the other one supplies the critical load that cannot be shutdown.

Electrical equipment that is improperly applied will not give reliable service regardless of how good or how much preventive maintenance is accomplished. The most reasonably accepted measure is to make a corrective modification.


An inspection analysis of the physical condition of a plant’s distribution system can be utilized (hopefully on a continual basis) to improve plant reliability. The following inspection requires little, if any, capital investment while providing a favorable increase in reliability:

a) Equipment should be periodically checked for proper condition, and programs should be initiated for preventive maintenance procedures as required.

1) Oil in transformers and circuit breakers should be periodically checked for mineral, carbon, and water content as well as level and temperature.

2) Molded case circuit breakers should be exercised periodically (that is, operated “on” to “off” to “on”).

3) Terminals should be tightened. Each terminal should be inspected for discoloration (overheating), which is generally caused by either a bad connection or equipment overload. Cabinets, etc., should be checked for excessive warmth. Remember that circuit breakers and fuses interrupt as a result of heat in the overload mode.

4) Surge arresters should be checked for their readiness to operate.

b) Distribution centers should be checked to see that spare fuses are available. Spare circuit breakers may also be necessary for odd sizes or special applications.

c) Switches, disconnect switches, bus work, and grounds should be checked for corrosion, and unintentional entry of water or corrosive foreign material. It may be wise to operate suspected switches to see that their mechanisms are free, so that faults can be properly isolated and switches safely re-fused.

d) The mechanical part of the electrical system should be checked.

1) The conduit, duct, cable tray, and busway systems should be well supported mechanically, and the grounding system should be electrically continuous. Employees can be shocked or injured if a circuit faults to ground without a solid continuous return path to the source interrupter.

Supports, such as wood poles, should be checked for excessive rusting or rotting, which would significantly reduce their mechanical strength.

2) Open wire circuits should be checked for insulator and surge arrester failure and contamination.

3) The system’s key locations (open area distribution centers and lines) should be checked for foreign growth, such as trees, weeds, shrubs, etc., as well as for general accessibility. The distribution centers should be free from storage of trash, flammables, or even general plant inventory.

4) Permanent and portable wiring should be checked for fraying or other loss of insulating value.

5) In general, the system should be checked for any obvious situations where accidents could precipitate an interruption.
e) The electrical supply room(s) should be thoroughly checked.

1) The relay and control power fuses should be intact (not blown).

2) All indicating lights should be operable and clearly visible.

3) All targets should be reset so that none show a tripping. Counters (if any) should be checked and the count (number) should be recorded.

4) The control power, batteries, emergency lighting, and emergency generation should be tested and checked to see that they are operational. In many cases, plants have been unable to transfer to their spare circuit or start their standby generator because of dead batteries.

f) Switches, conduits, busways, and duct systems should be checked for overheating. This could be caused by overloaded equipment, severely unbalanced loads, or poor connections.


Codes, standards, or other documents referred to in this specification are to be considered as part of it. In the event of a conflict between this specification and the National Electrical Safety Code (NESC), the NESC shall be followed. In the event of a conflict between this specification and all other referenced documents, this specification shall be followed.

If a conflict between several referenced documents occurs, the more stringent requirement shall be followed. If clarification is necessary, contact the owner.

The most recent editions of the following codes and standards shall be followed in the design, manufacture, inspection, testing, and shipment of spun, prestressed concrete poles:

3.1 American Concrete Institute (ACI):
ACI 318, Building Code Requirements for Reinforced Concrete

3.2 Prestressed Concrete Institute (PCI):
MNL 116, Manual for Quality Control for Plants and Production of Precast Prestressed Concrete Products

3.3 American Welding Society (AWS):
AWS D1.1, Recommended Procedures for Welding, Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Construction

3.4 American Society for Testing Materials (ASTM):
ASTM A82 Steel Wire Plain, For Concrete Reinforcement
ASTM A416 Steel Strand, Uncoated 7-wire For Prestressed Concrete
ASTM A421 Uncoated Stressed Relieved Steel For Prestressed Concrete
ASTM A496 Steel Wire, Deformed For Concrete Reinforcement
ASTM A615/A615M, Deformed and Plain Billet-Steel Bars For Concrete Reinforcement
ASTM A617/A617M, Axle-Steel Deformed and Plain Bars For Concrete Reinforcement
ASTM A641M Zinc Coated (Galvanized) Carbon Steel Wire (Metric)
ASTM A706A/A706M, Low Alloy Steel Deformed Bars For Concrete Reinforcement
ASTM C31 and 39, Specifications for Sampling Concrete and Testing Concrete Cylinders
ASTM C33 Concrete Aggregates
ASTM C150 Portland Cement
ASTM C172 Sampling Freshly Mixed Concrete
ASTM C289 Testing Potential Alkali-Silica Reactivity of Aggregates
ASTM C494 Chemical Admixtures For Concrete
ASTM C881 Epoxy-Resin-Base Bonding Systems for Concrete
ASTM C1089 Standard Specification For Spun Cast Prestressed Concrete Poles

3.5 Industrial Fasteners Institute (IFI): Fastener Standards

3.6 American National Standards Institute (ANSI) C2, National Electrical Safety Code

3.7 American Society of Civil Engineers/Prestressed Concrete Institute (ASCE/PCI) Joint Committee on Concrete Poles:
Guide for the Design of Prestressed Concrete Poles, latest edition 


Differential relaying with overcurrent relays requires connecting current transformers in each phase of each circuit in parallel with an overcurrent relay for that phase. (See Fig 1, illustrating the connections for 1 phase of a 3-phase system.)

While it is permissible to utilize auxiliary current transformers to match ratios, it is most desirable for all current transformers to have the same ratio on the tap used so that auxiliary current transformers are not required.

Ground differential relaying, with an overcurrent relay for bus ground faults only, has been applied where current transformers are not available to dedicate to bus protection and where the bus construction minimizes the possibility of phase faults. In this case only the current transformer residual current circuits are connected, as shown in Fig 1.

The usual precautions concerning burden, etc, apply. Where bus selection flexibility is provided, the system can be switched. Switching of residual current is less hazardous than switching phase currents.

When applying overcurrent relays in differential schemes, special consideration should be given to the current transformer saturation problem. Based on an assumed value of residual flux, calculations can be made to estimate the extent of the error due to dc saturation of the current transformer core.

In general, this type of protection should be limited to locations that are electrically remote from generating stations which can produce large dc offset fault currents with long time constants.

To minimize possible incorrect operations, the relay may be set less sensitive, time delay may be increased, and inverse time induction-type overcurrent relays with short time characteristics may be used.

The induction principle and design makes these relays less sensitive to the dc and harmonic components of the differential current.

Depending upon the application, delaying relay operation allows the transient differential current to subside before the relay operates.


 Water treeing can range from predominantly electromechanical in nature to essentially electrochemical. Agreat deal of the early laboratory work was carried out with “water needle” configurations, which produce extremely high electric fields at the tip of a needle-shaped, water-filled cavity.

The electric field at the tip was usually high enough to produce an electrical tree if the cavity were not filled with water, and the water tree grows in hours to days, rather than months to years as for a water tree grown under utility operating conditions.

Dorris, et al. Investigated electrical signals generated by the growth of such water trees. An analysis of their data suggests that the measured electrical signals could be produced by a sudden 0.01 to 0.1 μm extension of the water tree channel.

This work provides clear evidence for the growth of essentially electromechanical trees at very high fields. Such trees probably grow through (i) electrochemical damage in the tree tip region, which weakens the polymer to the point that (ii) electromechanical forces cause a sudden yielding of the polymer and extension of the tree in the range of 0.01 to 0.1 μm.

Because the electric field and resulting electromechanical forces are relatively large [9], relatively little damage to the polymer in the tree tip region is required to reduce the yield stress of the polymer sufficiently that the electromechanical forces cause yielding and extension of the tree channel.

For high-field, water needle-induced water trees, micro- infrared spectra of the resulting water tree indicate relatively little electro-oxidation, which progresses slowly relative to the time frame (days) in which the tree growth takes place under these high field conditions.

Under long-term utility service conditions, the electric field is quite low, typically 1-3 kV/mm, as are the resulting electromechanical forces.

The polymer must undergo substantial electrochemical degradation to reduce the yield stress to the point that the water tree can extend, and micro-infrared spectra of service-induced water trees show evidence of appreciable electro-oxidation in the tree region.


NFPA 72 classifies fire alarm systems as follows.

A system of devices that produces an alarm signal in the household for the purpose of notifying the occupants of the presence of fire so that they will evacuate the premises.

A system that sounds an alarm at the protected premises as the result of the manual operation of a fire alarm box or the operation of protection equipment or systems, such as water flowing in a sprinkler system, the discharge of carbon dioxide, the detection of smoke, or the detection of heat.

A system connected to a municipal fire alarm system for transmitting an alarm of fire to the public fire service communications center.

Fire alarms from an auxiliary fire alarm system are received at the public fire service communications center on the same equipment and by the same methods as alarms transmitted manually from municipal fire alarm boxes located on streets. There are three subtypes of this system; local energy, parallel telephone, and shunt.

A system installed in accordance with NFPA 72 to transmit alarm, supervisory, and trouble signals from one or more protected premises to a remote location at which appropriate action is taken.

An installation of fire alarm systems that serves contiguous and noncontiguous properties, under one ownership, from a proprietary supervising station located at the protected property, at which trained, competent personnel are in constant attendance.

This includes the proprietary supervising station; power supplies; signal-initiating devices; initiating device circuits; signal notification appliances; equipment for the automatic, permanent visual recording of signals; and equipment for initiating the operation of emergency building control services.

A system or group of systems in which the operations of circuits and devices are transmitted automatically to, recorded in, maintained by, and supervised from a listed central station having competent and experienced servers and operators who, upon receipt of a signal, take action as required by NFPA 72.

Such service is to be controlled and operated by a person, firm, or corporation whose business is the furnishing, maintaining, or monitoring of supervised fire alarm systems.

A system of alarm-initiating devices, receiving equipment, and connecting circuits (other than a public telephone network) used to transmit alarms from street locations to the public fire service communications center.


Blown optical fiber technology is an exciting method of delivering a fiber solution that provides unmatched flexibility and significant cost savings when compared to conventional fiber cables. In a blown optical fiber system, the fiber route is “plumbed” with small tubes.

These tubes, known as microduct, come in 5- and 8 mm diameters and are approved for riser, plenum, or outside-plant applications.They are currently available as a single microduct, or with two, four, or seven microducts bundled (straight, not twisted) and covered with an outer sheath, called multiducts.

They are lightweight and easy to handle. Splicing along the route is accomplished through simple push-pull connectors. These microducts are empty during installation, thereby eliminating the possibility of damaging the fibers during installation.

Fiber is then installed, or “blown,” into the microduct.The fiber is fed into the microduct and rides on a current of compressed air. Carried by viscous drag, the fibers are lifted into the airstream and away from the wall of the microduct, thereby eliminating friction even around tight bends.

In a relatively short period, coated fibers can be blown for distances up to 1 km (3281 ft) in a single run of 8-mm-diameter microduct, up to 1000 ft vertical, or through any network architecture or topology turning up to 300 tight corners with 90° bends of 1-in. radius for over 1000 ft, using 5-mm-diameter microduct.

The practical benefits of BOFT systems translate directly into financial benefits for the end user. For most installations, the cost of a BOFT infrastructure is similar to or slightly higher than the cost for conventional fiber cabling.

Savings can be realized during the initial installation because (1) it simplifies the cable installation by allowing the pulling of empty or unpopulated microduct; (2) fewer, if any, fiber splices may be required; and (3) you only pay up front for those fibers that you need immediately. The additional expense of hybrid cables is eliminated.

True cost savings and the convenience of blown optical fiber are realized during the first fiber upgrade or during moves, additions, and changes. An upgrade of an existing fiber backbone will generally incur workplace disruptions such as removing a ceiling grid, moving office furniture, and network downtime that requires the work to be done outside normal business hours.

New fibers can be added to a BOFT system simply by accessing an existing unpopulated microduct and blowing in the fibers. There is no disruption to the workplace, and the process requires a minimal amount of time to complete.

In the event that there are no empty microducts, the existing fiber can be blown out in minutes and replaced with the new fiber type(s) immediately. The flexibility of BOFT makes it particularly amenable to renovation and retrofit applications.


Symmetrical Components, first developed by C.L.Fortescue in 1918, is a powerful technique for analyzing unbalanced 3f systems. Fortescue defined a linear transformation from 3f components to a new set of components called symmetrical components.

The advantage of this transformation is that for balance three phase networks the equivalent circuit obtained for the symmetrical components, called sequence networks, are separated into three uncoupled networks.

Further more, for unbalanced three phase systems, the three sequence networks are connected only at the points of unbalance. As a result, sequence networks for many cases of unbalanced three phase systems are relatively easy to analyze.

The symmetrical component method is basically a modeling technique that permits systematic analysis and design of three phase systems. Decoupling a detailed three phase network into three simpler sequence networks reveals complicated phenomena in more simplistic terms.

Sequence network results can then be superimposed to obtain three phase results. The application of symmetrical components to unsymmetrical fault studies is indispensable.

In accordance with Fortescue, the three phase voltages, VR , VY , and V B are resolved into three sets of sequence components:

1. Zero sequence, consisting of three phasors with equal magnitudes and with zero phase displacement.

2. Positives equence, consisting of three phasors with equal magnitudes, ±120 o phase displacement and positive sequence.

3. Negative sequence, consisting of three phasors with equal magnitudes, ±120 o phase displacement and negative sequence.

1. The sequence components do not exist as physical quantities in the network.

2. A balanced system has no negative or zero sequence components therefore: actual balanced system = positive sequence system

3. The generated emf is balanced, and therefore positive phase sequence only.

4. In a 3phase 3wire system, there are no zero sequence components, because there is no neutral connection.


Ground Rods.
Vertically driven ground rods or pipes are the most common type of made electrode. Rods or pipes are generally used where bedrock is beyond a depth of 3 meters (10 feet). Ground rods are commercially manufactured in 1.27, 1.59, 1.90 and 2.54 cm (1/2, 5/8, 3/4 and 1 inch) diameters and in lengths from 1.5 to 12 meters (5 to 40 feet).

For most applications, ground rods of 1.90 cm (3/4 inch) diameter, and length of 3.0 meters (10 feet), are used. Copper-clad steel ground rods are required because the steel core provides the strength to withstand the driving force and the copper provides corrosion protection and is compatible with copper or copper-clad interconnecting cables.

Buried Horizontal Conductors.
Where bedrock is near the surface of the earth, the use of driven rods is unpractical. In such cases, horizontal strips of metal, solid wires, or stranded cables buried 0.48 to 0.86 meters (18 to 36 inches) deep may be used effectively.

With long strips, reactance increases as a factor of the length with a consequent increase in impedance. A low impedance is desirable for minimizing lightning surge voltages. Therefore, several wires, strips, or cables arranged in a star pattern, with the facility at the center, is preferable to one long length of conductor.

Grid systems, consisting of copper cables buried about 15.24 cm (6 inches) in the ground and forming a network of squares, are used to provide equipotential areas throughout the facility area. Such a system usually extends over the entire area.

The spacing of the conductors, subject to variation according to requirements of the installation, may normally be 0.6 to 1.2 meters (2 to 4 feet) between cables. The cables must be bonded together at each crossover.

Grids are generally required only in antenna farms or substation yards and other areas where very high fault currents are likely to flow into the earth and hazardous step potentials may exist or soil conditions prohibit installation of other ground systems.

Antenna counterpoise systems shall be installed in accordance with guidance requirements of the manufacturer.

Rectangular or circular plate electrodes should present a minimum of 0.09 square meters (2 square feet) of surface contact with the soil. Iron or steel plates should be at least 0.64 cm (1/4 inch) thick and nonferrous metals should be at least 0.15 cm (0.06 inches) thick.

A burial depth of 1.5 to 2.4 meters (5 to 8 feet) below grade should be maintained. This system is considered very expensive for the value produced and generally not recommended.

Metal Frameworks of Buildings.
The metal frameworks of buildings may exhibit less than 10 ohms, depending upon the size of the building, the type of footing, and particular location. Buildings that rest on steel pilings in particular may exhibit connection to earth.

For this low resistance to be used advantageously, it is necessary framework be bonded together. a resistance to earth of the type of subsoil at a a very low resistance that all elements of the framework bonded together.

Water Pipes.
Metal underground pipes have traditionally been relied upon for grounding electrodes. The resistance to earth provided by piping systems is usually quite low because of the extensive contact made with soil.

Municipal water systems in particular establish contact with the soil over wide areas. For water pipes to be effective, any possible discontinuities must be bridged with bonding jumpers. The NEC requires that any water metering equipment and service unions be bypassed with a jumper not less than that required for the grounding connector.

However, stray or fault currents flowing through the piping network into the earth can present a hazard to workmen making repairs or modifications to the water system. For example, if the pipes supplying a building are disconnected from the utility system for any reason, that portion connected to the building can rise to a hazardous voltage level relative to the rest of the piping system and possibly with respect to the earth.

In particular, if the resistance that is in contact with the soil near the building happens to be high, a break in the pipe at even some distance from the building may pose a hazardous condition to unsuspecting workmen.

Some water utilities are inserting non-conductive couplings in the water mains at the point of entrance to buildings to prevent such possibilities.

For these reasons, the water system should not be relied upon as a safe and dependable earth electrode for a facility and should be supplemented with at least one other ground system.

Incidental Metals.
There may be a number of incidental, buried , metallic objects in the vicinity of the earth electrode subsystem. These objects should be connected to the system to reduce the danger of potential differences during lightning or power fault conditions: their connection will also reduce the resistance to earth of the earth electrode subsystem. Such additions to the earth electrode subsystem should include the rebar in concrete footings, buried tanks, and piping.

Well Casings.
Well casing can offer a low resistance contact with the earth. In some areas, steel pipe used for casing in wells can be used as a ground electrode. Where wells are located on or near a site, the resistance to earth of the casing should be measured and, if below 10 ohms, the well casing can be considered for use as a ground electrode.


Immediately after the alignment of a line has been finalized to the satisfaction of both the engineer and the borrower, a survey should be made to map the route of the line. Based on this survey, plan-profile drawings will be produced and used to spot structures.

Long corridors can usually be mapped by photogrammetry at less cost than equivalent ground surveys. The photographs will also contain information and details which could not otherwise be discovered or recorded.

Aerial survey of the corridor can be accomplished rapidly, but proper conditions for photography occur only on a comparatively few days during the year. In certain areas, photogrammetry is impossible. It cannot be used where high conifers conceal the ground or in areas such as grass-covered plains that contain no discernible objects.

Necessary delays and overhead costs inherent in air mapping usually prevent their use for short lines. When using photogrammetry to develop plan-profile drawings, proper horizontal and vertical controls should first be established in accordance with accepted surveying methods.

From a series of overlapping aerial photographs, a plan of the transmission line route can be made. The plan may be in the form of an orthophoto or it may be a planimetric map. The overlapping photos also enable the development of profile drawings.

The tolerance of plotted ground elevations to the actual ground profile will depend on photogrammetric equipment, flying height, and accuracy of control points.

Survey data can be gathered using a helicopter-mounted laser to scan existing lines and/or topography. Three dimensional coordinates of millions of points can be gathered while also taking forward and downward looking videos. These points can be classified into ground points, structure points and wire points.

If use of photogrammetry or laser-derived survey information for topographic mapping is not applicable for a particular line, then transit and tape or various electronic instruments for measuring distance should be used to make the route survey. This survey will generally consist of placing stakes at 100 foot intervals with the station measurement suitably marked on the stakes.

It will also include the placement of intermediate stakes to note the station at property lines and reference points as required. The stakes should be aligned by transit between the hub stakes set on the preliminary survey.

The survey party needs to keep notes showing property lines and topographic features of obstructions that would influence structure spotting. To facilitate the location of the route by others, colored ribbon or strips of cloth should be attached at all fence crossings and to trees at regular intervals along the route (wherever possible).

As soon as the horizontal control survey is sufficiently advanced, a level party should start taking ground elevations along the center line of the survey. Levels should be taken at every 100 foot stations and at all intermediate points where breaks in the ground contour appear.

Wherever the ground slopes more than 10 percent across the line of survey, side shots should be taken for a distance of at least 10 feet beyond the outside conductor's normal position. These elevations to the right and left of the center line should be plotted as broken lines.

The broken lines represent side hill profiles and are needed, when spotting structures, to assure proper ground clearance under all conductors, and proper pole lengths and setting depths for multiple-pole structures.


Electric fields produce forces, just as do magnetic fields. You have probably noticed this when your hair feels like it’s standing on end in very dry or cold weather.

You’ve probably heard that people’s hair really does stand straight out just before a lightning bolt hits nearby; this is no myth. Maybe you performed experiments in science classes to observe this effect.

The most common device for demonstrating electrostatic forces is the electroscope. It consists of two foil leaves, attached to a conducting rod, and placed in a sealed container so that air currents will not move the foil leaves (Fig. 3-3).

When a charged object is brought near, or touched to, the contact at the top of the rod, the leaves stand apart from each other. This is because the two leaves become charged with like electric poles—either an excess or a deficiency of electrons—and like poles always repel.

The extent to which the leaves stand apart depends on the amount of electric charge. It is somewhat difficult to actually measure this deflection and correlate it with charge quantity; electroscopes do not make very good meters.

But variations on this theme can be employed, so that electrostatic forces can operate against tension springs or magnets, and in this way, electrostatic meters can be made.

An electrostatic device has the ability to measure alternating electric charges as well as steady charges. This gives electrostatic meters an advantage over electromagnetic meters (galvanometers). If you connect ac to the coil of the galvanometer device, the compass needle might vibrate, but will not give a clear deflection.

This is because current in one direction pulls the meter needle one way, and current in the other direction will deflect the needle the opposite way. But if an alternating electric field is connected to an electrostatic meter, the plates will repel whether the charge is positive or negative. The deflection will be steady, therefore, with ac as well as with dc.

Most electroscopes aren’t sensitive enough to show much deflection with ordinary 117-V utility voltage. Don’t try connecting 117 V to an electroscope anyway; it might not deflect the foil leaves, but it can certainly present a danger to your body if you bring it out to points where you can readily come into physical contact with it.

An electrostatic meter has another property that is sometimes an advantage in electrical or electronic work. This is the fact that the device does not draw any current, except a tiny amount at first, needed to put a charge on the plates.

Sometimes, an engineer or experimenter doesn’t want the measuring device to draw current, because this affects the behavior of the circuit under test. Galvanometers, by contrast, always need at least a little bit of current in order to operate.

You can observe this effect by charging up a laboratory electroscope, say with a glass rod that has been rubbed against a cloth. When the rod is pulled away from the electroscope, the foil leaves will remain standing apart.

The charge just sits there. If the electroscope drew any current, the leaves would immediately fall back together again, just as the galvanometer compass needle returns to magnetic north the instant you take the wire from the battery.


The flow of electric current may be visualized by comparing it with the flow of water. Where water is made to flow in pipes, electric current is conducted along wires.

To move a definite amount of water from one point to another in a given amount of time, either a large-diameter pipe may be used and a low pressure applied on the water to force it through, or a small-diameter pipe may be used and a high pressure applied to the water to force it through.

While doing this it must be borne in mind that when higher pressures are used, the pipes must have thicker walls to withstand that pressure (see Figure 1-3).

The same rule applies to the transmission of electric current. In this case, the diameter of the pipe corresponds to the diameter of the wire and the thickness of the pipe walls corresponds to the thickness of the insulation around the wire, as shown in Figure 1-4.


Low voltages require large conductors, and high voltages require smaller conductors. This was illustrated with a water analogy. A small amount of pressure may be applied and the water will flow through a large pipe, or more pressure may be applied and the water will flow through a slimmer pipe.

This principle is basic in considering the choice of a voltage (or pressure) for a distribution system. There are two general ways of transmitting electric current-overhead and underground.

In both cases, the conductor may be copper or requires careful studies. Experts work out the system three or four different ways. For instance, they figure all the expenses involved in a 4000-volt (4 kV), in a 34,500-volt (34.5 kV), or a 13,000-volt (13 kV) system.

The approximate costs of necessary equipment, insulators, switches, and so on, and their maintenance and operation must be carefully evaluated. The future with its possibilities of increased demand must also be taken into consideration.

Safety is the most important factor. The National Electric Safety Code includes many limitations on a utility company’s choice of voltage.

Some municipal areas also set up their own standards. The utility company must weigh many factors before determining a voltage for distribution. It was mentioned that safety is the most important factor in determining voltages for distributing electricity.

Here’s why!

Consider what happens when a water pipe carrying water at high pressure suddenly bursts. The consequences may be fatal and damage considerable. The same is true of electrical conductors.

Safeguarding the life and limb of the public as well as workers is an important responsibility of the utility company.

Table 1-1 shows typical transmission and distribution system voltages in use at the present time.

Table 1-1. Typical Voltages in Use
Main Sub Primary Distribution
Transmission Transmission Distribution Secondary
69,000 V 13,800 V 2,400 V 120 V
138,000 V 23,000 V 4,160 V 120/240 V
220,000 V 34,500 V 13,800 V 240 V
345,000 V 69,000 V 23,000 V 277/480 V
500,000 V 138,000 V 34,500 V 480 V


What is Demand?
Electrical energy is commonly measured in units of kilowatthours. Electrical power is expressed as kilowatthours per hour or, more commonly, kilowatts.

Demand is defined as power averaged over some specified period. Figure 7.2 shows a sample power curve representing instantaneous power. In the time interval shown, the integrated area under the power curve represents the energy consumed during the interval.

This energy, divided by the length of the interval (in hours) yields “demand.” In other words, the demand for the interval is that value of power that, if held constant over the interval, would result in an energy consumption equal to that energy the customer actually used.

Demand is most frequently expressed in terms of real power (kilowatts). However, demand may also apply to reactive power (kilovars), apparent power (kilovolt-amperes), or other suitable units. Billing for demand is commonly based on a customer’s maximum demand reached during the billing period.

Why is Demand Metered?
Electrical conductors and transformers needed to serve a customer are selected based on the expected maximum demand for the customer. The equipment must be capable of handling the maximum levels of voltages and currents needed by the customer.

A customer with a higher maximum demand requires a greater investment by the utility in equipment. Billing based on energy usage alone does not necessarily relate directly to the cost of equipment needed to serve a customer.

Thus, energy billing alone may not equitably distribute to each customer an appropriate share of the utility’s costs of doing business.

For example, consider two commercial customers with very simple electricity needs. Customer A has a demand of 25 kW and operates at this level 24 hours per day.

Customer B has a maximum demand of 100 kW but operates at this level only 4 hours per day. For the remaining 20 hours of the day, “B” operates at a 10 kW power level.

“A” uses 25 kW × 24 hr = 600 kWh per day

“B” uses (100 kW × 4 hr) + (10 kW × 20 hr) = 600 kWh per day

Assuming identical billing rates, each customer would incur the same energy costs. However, the utility’s equipment investment will be larger for Customer B than for Customer A.

By implementing a charge for demand as well as energy, the utility would bill Customer A for a maximum demand of 25 kW and Customer B for 100 kW. “B” would incur a larger total monthly bill, and each customer’s bill would more closely represent the utility’s cost to serve.


A number of situations exist where a generator could be driven as a motor. Anti-motoring protection will more specifically apply in situations where the prime-mover supply is removed for a generator supplying a network at synchronous speed with the field normally excited.

The power system will then drive the generator as a motor.

A motoring condition may develop if a generator is connected improperly to the power system. This will happen if the generator circuit breaker is closed inadvertently at some speed less than synchronous speed.

Typical situations are when the generator is on turning gear, slowing down to a standstill, or has reached standstill. This motoring condition occurs during what is called “generator inadvertent energization.”

The protection schemes that respond to this situation are different and will be addressed later in this article. Motoring will cause adverse effects, particularly in the case of steam turbines.

The basic phenomenon is that the rotation of the turbine rotor and the blades in a steam environment will cause windage losses.

Windage losses are a function of rotor diameter, blade length, and are directly proportional to the density of the enclosed steam. Therefore, in any situation where the steam density is high, harmful windage losses could occur.

From the preceding discussion, one may conclude that the anti-motoring protection is more of a prime mover protection than a generator protection.

The most obvious means of detecting motoring is to monitor the flow of real power into the generator. If that flow becomes negative below a preset level, then a motoring condition is detected.

Sensitivity and setting of the power relay depends upon the energy drawn by the prime mover considered now as a motor. With a gas turbine, the large compressor represents a substantial load that could reach as high as 50% of the unit nameplate rating. Sensitivity of the power relay is not an issue and is definitely not critical.

With a diesel type engine (with no firing in the cylinders), load could reach as high as 25% of the unit rating and sensitivity, once again, is not critical. With hydroturbines, if the blades are below the tail-race level, the motoring energy is high.

If above, the reverse power gets as low as 0.2 to 2% of the rated power and a sensitive reverse power relay is then needed. With steam turbines operating at full vacuum and zero steam input, motoring will draw 0.5 to 3% of unit rating. A sensitive power relay is then required.


A loss-of-excitation on a generator occurs when the field current is no longer supplied. This situation can be triggered by a variety of circumstances and the following situation will then develop:

1. When the field supply is removed, the generator real power will remain almost constant during the next seconds. Because of the drop in the excitation voltage, the generator output voltage drops gradually. To compensate for the drop in voltage, the current increases at about the same rate.

2. The generator then becomes underexcited and it will absorb increasingly negative reactive power.

3. Because the ratio of the generator voltage over the current becomes smaller and smaller with the phase current leading the phase voltage, the generator positive sequence impedance as measured at its terminals will enter the impedance plane in the second quadrant.

Experience has shown that the positive sequence impedance will settle to a value between Xd and Xq.

The most popular protection against a loss-of-excitation situation uses an offset-mho relay as shown in Fig. 9.8 (IEEE, 1989). The relay is supplied with generator terminals voltages and currents and is normally associated with a definite time delay.

Many modern digital relays will use the positive sequence voltage and current to evaluate the positive sequence impedance as seen at the generator terminal.

Figure 9.9 shows the digitally emulated positive sequence impedance trajectory of a 200 MVA generator connected to an infinite bus through an 8% impedance transformer when the field voltage was removed at 0 second time.


Protection against stator-to-ground fault will depend to a great extent upon the type of generator grounding. Generator grounding is necessary through some impedance in order to reduce the current level of a phase-to-ground fault.

With solid generator grounding, this current will reach destructive levels. In order to avoid this, at least low impedance grounding through a resistance or a reactance is required.

High-impedance through a distribution transformer with a resistor connected across the secondary winding will limit the current level of a phase-to-ground fault to a few primary amperes.

The most common and minimum protection against a stator-to-ground fault with a high-impedance grounding scheme is an overvoltage element connected across the grounding transformer secondary, as shown in Fig. 9.5.

For faults very close to the generator neutral, the overvoltage element will not pick up because the voltage level will be below the voltage element pick-up level. In order to cover 100% of the stator windings, two techniques are readily available:

1. use of the third harmonic generated at the neutral and generator terminals, and
2. voltage injection technique.

Looking at Fig. 9.6, a small amount of third harmonic voltage will be produced by most generators at their neutral and terminals. The level of these third harmonic voltages depends upon the generator operating point as shown in Fig. 9.6a.

Normally they would be higher at full load. If a fault develops near the neutral, the third harmonic neutral voltage will approach zero and the terminal voltage will increase. However, if a fault develops near the terminals, the terminal third harmonic voltage will reach zero and the neutral voltage will increase.

Based on this, three possible schemes have been devised. The relays available to cover the three possible choices are:

1. Use of a third harmonic undervoltage at the neutral. It will pick up for a fault at the neutral.
2. Use of a third harmonic overvoltage at the terminals. It will pick up for a fault near the neutral.
3. The most sensitive schemes are based on third harmonic differential relays that monitor the ratio of third harmonic at the neutral and the terminals (Yin et al., 1990).


Tellegen’s theorem states:

In an arbitrarily lumped network subject to KVL and KCL constraints, with reference directions of the branch currents and branch voltages associated with the KVL and KCL constraints, the product of all branch currents and branch voltages must equal zero.

Tellegen’s theorem may be summarized by the equation

where the lower case letters v and j represent instantaneous values of the branch voltages and branch currents, respectively, and where b is the total number of branches. A matrix representation employing the branch current and branch voltage vectors also exists. Because V and J are column vectors
V · J = VT J = J T V

The prerequisite concerning the KVL and KCL constraints in the statement of Tellegen’s theorem is of crucial importance.

Example 3.3. Figure 3.16 displays an oriented graph of a particular network in which there are six branches labeled with numbers within parentheses and four nodes labeled by numbers within circles. Several known branch currents and branch voltages are indicated.

Because the type of elements or their values is not germane to the construction of the graph, the other branch currents and branch voltages may be evaluated from repeated applications of KCL and KVL. KCL may be used first at the various nodes.

node 3: j2 = j6 – j4 = 4 – 2 = 2 A
node 1: j3 = –j1 – j2 = –8 – 2 = –10 A
node 2: j5 = j3 – j4 = –10 – 2 = –12 A

Then KVL gives

v3 = v2 – v4 = 8 – 6 = 2 V
v6 = v5 – v4 = –10 – 6 = –16 V
v1 = v2 + v6 = 8 – 16 = –8 V

The transpose of the branch voltage and current vectors are
VT = [–8 8 2 6 –10 –16] V
JT = [8 2 –10 2 –12 4] V

The scalar product of V and J gives
–8(8) + 8(2) + 2(–10) + 6(2) + (–10)(–12) + (–16)(4) = –148 + 148 = 0
and Tellegen’s theorem is confirmed.


The resistance for most resistors changes with temperature. The temperature coefficient of electrical resistance is the change in electrical resistance of a resistor per unit change in temperature.

The temperature coefficient of resistance is measured in OHM/°C. The temperature coefficient of resistors may be either positive or negative.

A positive temperature coefficient denotes a rise in resistance with a rise in temperature; a negative temperature coefficient of resistance denotes a decrease in resistance with a rise in temperature. Pure metals typically have a positive temperature coefficient of resistance, while some metal alloys such as constantin and manganin have a zero temperature coefficient of resistance.

Carbon and graphite mixed with binders usually exhibit negative temperature coefficients, although certain choices of binders and process variations may yield positive temperature coefficients.

The temperature coefficient of resistance is given by
R(T2) = R(T1) [ 1+ ALPHAn (t2-t1)]

ALPHAn = is the temperature coefficient of electrical resistance at reference temperature @ T1

R(T2) is the resistance at temperature T2(W), and R(T1) is the resistance at temperature@ T1(W). The reference temperature is usually taken to be 20°C.

Because the variation in resistance between any two temperatures is usually not linear as predicted by Eq. , common practice is to apply the equation between temperature increments and then to plot the resistance change versus temperature for a number of incremental temperatures.


HRC or current-limiting fuses have an interrupting rating of 200 kA and are recognized by a letter designation system common to North American fuses. In the United States they are known as Class J, Class L, Class R, etc., and in Canada they are known as HRCI-J, HRC-L, HRCI-R, and so forth.

HRC fuses are available in ratings up to 600 V and 6000 A. The main differences among the various types are their dimensions and their short circuit performance (Ip and I2t) characteristics.

One type of HRC fuse found in Canada, but not in the United States, is the HRCII-C or Class C fuse. This fuse was developed originally in England and is constructed with bolt-on-type blade contacts. It is available in a voltage rating of 600 V with ampere ratings from 2 to 600 A.

Some higher ampere ratings are also available but are not as common. HRCII-C fuses are primarily regarded as providing short-circuit protection only. Therefore, they should be used in conjunction with an overload device.

HRCI-R or Class R fuses were developed in the United States. Originally constructed to Standard or Class H fuse dimensions, they were classified as Class K and are available in the United States with two levels of short circuit performance characteristics: Class K1 and Class K5. However, they are not recognized in Canadian Standards.

Under fault conditions, Class K1 fuses limit the Ip and I2t to lower levels than do Class K5 fuses. Since both Class K1 and K5 are constructed to Standard or Class H fuse dimensions, problems with interchangeability occur.

As a result, a second generation of these K fuses was therefore introduced with a rejection feature incorporated in the end caps and blade contacts. This rejection feature, when used in conjunction with rejection-style fuse clips, prevents replacement of these fuses with Standard or Class H 10-kA I.R. fuses.

These rejection style fuses are known as Class RK1 and Class RK5. They are available with time-delay or non-time delay characteristics and with voltage ratings of 250 or 600 V and ampere ratings up to 600 A. In Canada, CSA has only one classification for these fuses, HRCI-R, which have the same maximum Ip and I2t current-limiting levels as specified by UL for Class RK5 fuses.

HRCI-J or Class J fuses are a more recent development. In Canada, they have become the most popular HRC fuse specified for new installations. Both time-delay and non-time-delay characteristics are available in ratings of 600 V with ampere ratings up to 600 A. They are constructed with dimensions much smaller than HRCI-R or Class R fuses and have end caps or blade contacts which fit into 600-V Standard or Class H type fuse clips.

However, the fuse clips must be mounted closer together to accommodate the shorter fuse length. Its shorter length, therefore, becomes an inherent rejection feature that does not allow insertion of Standard or HRCI-R fuses.

The blade contacts are also drilled to allow bolt-on mounting if required. CSA and UL specify these fuses to have maximum short-circuit current-limiting Ip and I2t limits lower than those specified for HRCI-R and HRCII-C fuses.

HRCI-J fuses may be used for a wide variety of applications. The time-delay type is commonly used in motor circuits sized at approximately 125 to 150% of motor full-load current. HRC-L or Class L fuses are unique in dimension but may be considered as an extension of the HRCI-J fuses for ampere ratings above 600 A.

They are rated at 600 V with ampere ratings from 601 to 6000 A. They are physically larger and are constructed with bolt-on-type blade contacts. These fuses are generally used in lowvoltage distribution systems where supply transformers are capable of delivering more than 600 A.

In addition to Standard and HRC fuses, there are many other types designed for specific applications. For example, there are medium- or high-voltage fuses to protect power distribution transformers and medium voltage motors.

There are fuses used to protect sensitive semiconductor devices such as diodes, SCRs, and triacs. These fuses are designed to be extremely fast under short-circuit conditions. There is also a wide variety of dedicated fuses designed for protection of specific equipment requirements such as electric welders, capacitors, and circuit breakers, to name a few.


Wire. A slender rod or filament of drawn metal. (This definition restricts the term wire to what would ordinarily be understood by the term solid wire. In the definition the word slender is used in the sense that the length is great in comparison with the diameter.

If a wire is covered with insulation, it is properly called an insulated wire, although the term wire refers primarily to the metal; nevertheless, when the context shows that the wire is insulated, the term wire will be understood to include the insulation.)

Conductor. A wire or combination of wires not insulated from one another, suitable for carrying a single electric current. (The term conductor does not include a combination of conductors insulated from one another, which would be suitable for carrying several different electric currents. Rolled conductors, such as busbars, are, of course, conductors but are not considered under the terminology given here.)

Stranded Conductor. A conductor composed of a group of wires or any combination of groups of wires. (The wires in a stranded conductor are usually twisted or braided together.)

Cable. A stranded conductor (single-conductor cable) or (2) a combination of conductors insulated from one another (multiconductor cable). The component conductors of the second kind of cable may be either solid or stranded, and this kind may or may not have a common insulating covering. The first kind of cable is a single conductor, while the second kind is a group of several conductors.

Strand. One of the wires or groups of wires of any stranded conductor.

Stranded Wire. A group of small wires used as a single wire. (A wire has been defined as a slender rod or filament of drawn metal. If such a filament is subdivided into several smaller filaments or strands and is used as a single wire, it is called stranded wire.

There is no sharp dividing line of size between a stranded wire and a cable. If used as a wire, for example in winding inductance coils or magnets, it is called a stranded wire and not a cable. If it is substantially insulated, it is called a cord, defined below.)

Cord. A small cable, very flexible and substantially insulated to withstand wear. (There is no sharp dividing line in respect to size between a cord and a cable and likewise no sharp dividing line in respect to the character of insulation between a cord and a stranded wire.)

Concentric Strand. A strand composed of a central core surrounded by one or more layers of helically laid wires or groups of wires.


 • Visual inspections — Most often, crews find gross problems, especially with drive-bys: severely degraded poles, broken conductor strands, and broken insulators. Some utilities do regular visual inspections; but more commonly, utilities have crews inspect circuits during other activities or have targeted inspections based on circuit performance.

The most effective inspections are those geared towards finding fault sources — these may be subtle; crews need to be trained to identify them.

• Infrared thermography — Roughly 40% of utilities surveyed use infrared inspections for overhead and underground circuits. Normally, crews watch a 20°C rise and initiate repair for more than a 30°C rise.

Infrared scanning primarily identifies poor connectors. Some utilities surveyed rejected infrared monitoring and did not find it cost effective. Other utilities found significant benefit.

• Wood pole tests — Visual inspections are most common for identifying weak poles. A few utilities use more accurate measures to identify the mechanical strength left in poles.

A hammer test, whacking the pole with a sledge, is slightly more sophisticated; a rotted pole sounds different when compared to a solid pole. Sonic testing machines are available that determine density and detect voids.

• Operation counts — Most utilities periodically read recloser operation and regulator tap changer counters to identify when they need maintenance.

• Oil tests — A few utilities perform oil tests on distribution transformers, reclosers, and/or regulators. While these tests can detect deterioration through the presence of water or dissolved gasses, the expense is difficult to justify for most distribution equipment.
free counters