Generation control and ED minimize the current cost of energy production and transmission within the range of available controls. Energy management is a supervisory layer responsible for economically scheduling production and transmission on a global basis and over time intervals consistent with cost optimization.

For example, water stored in reservoirs of hydro plants is a resource that may be more valuable in the future and should, therefore, not be used now even though the cost of hydro energy is currently lower than thermal generation.

The global consideration arises from the ability to buy and sell energy through the interconnected power system; it may be more economical to buy than to produce from plants under direct control. Energy accounting processes transaction information and energy measurements recorded during actual operation as the basis of payment for energy sales and purchases.

Energy management includes the following functions:
. System load forecast: Forecasts system energy demand each hour for a specified forecast period of 1 to 7 days.

. Unit commitment: Determines start-up and shut-down times for most economical operation of thermal generating units for each hour of a specified period of 1 to 7 days.

. Fuel scheduling: Determines the most economical choice of fuel consistent with plant requirements, fuel purchase contracts, and stockpiled fuel.

. Hydro-thermal scheduling: Determines the optimum schedule of thermal and hydro energy production for each hour of a study period up to 7 days while ensuring that hydro and thermal constraints are not violated.

. Transaction evaluation: Determines the optimal incremental and production costs for exchange (purchase and sale) of additional blocks of energy with neighboring companies.

. Transmission loss minimization: Recommends controller actions to be taken in order to minimize overall power system network losses.

. Security constrained dispatch: Determines optimal outputs of generating units to minimize production cost while ensuring that a network security constraint is not violated.

. Production cost calculation: Calculates actual and economical production costs for each generating unit on an hourly basis.


Wood poles are considerably cheaper than steel for many types of construction. The lower cost is due, in part, to the more conservative basis of design normally adopted for steel.

Generally, steel structures are designed to support safely one or more broken conductors, whereas wood structures are often not so designed. It is logical that the reasons for choosing the more expensive steel construction should require conservative design throughout and that conditions justifying the cheaper and shorter-lived wood structures would warrant accepting some of the more theoretical hazards.

For voltages of 69 kV and lower, wood is quite generally used. Wood-pole construction for many years has been used for all voltages up to and including 345 kV. H frames with various modifications have been designed, the most popular using the main crossarm as the bottom member of a truss.

Butt-treated cedar and full-treated pine are used almost exclusively in transmission-line construction; the use of untreated poles has been practically abandoned as uneconomical since the supply of chestnut and northern cedar poles has been exhausted. Treated fir has also been supplied in some quantity from the Northwest.

Cedar poles resist decay, but satisfactory life is not secured unless the butt is treated. The pole is usually treated from the butt to about 2 ft above the ground line.

The balance of the pole is not treated. Pine and fir require complete treatment of practically all the sapwood. This treatment is applied under pressure.

No universally effective protection has been devised against woodpecker damage. Some localities are often subject to serious epidemics of woodpecker trouble.

Preservative Treatment. 
Pole decay is due to a fungus which requires air, moisture, warmth, and food for its subsistence; the wood o 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”)


SCADA, with its relatively expensive RTUs installed at distribution substations, can provide status and measurements for distribution feeders at the substation. Distribution automation equipment is now available to measure and control at locations dispersed along distribution circuits.

This equipment can monitor sectionalizing devices (switches, interruptors, fuses), operate switches for circuit reconfiguration, control voltage, read customers’ meters, implement time-dependent pricing (on-peak, off-peak rates), and switch customer equipment to manage load.

This equipment requires significantly increased functionality at distribution control centers.

Distribution control center functionality varies widely from company to company, and the following list is evolving rapidly.

. Data acquisition: Acquires data and gives the operator control over specific devices in the field. Includes data processing, quality checking, and storage.

. Feeder switch control: Provides remote control of feeder switches.

. Tagging and alarms: Provides features similar to SCADA.

. Diagrams and maps: Retrieves and displays distribution maps and drawings. Supports device selection from these displays. Overlays telemetered and operator-entered data on displays.

. Preparation of switching orders: Provides templates and information to facilitate preparation of instructions necessary to disconnect, isolate, reconnect, and reenergize equipment.

. Switching instructions: Guides operator through execution of previously prepared switching orders.

. Trouble analysis: Correlates data sources to assess scope of trouble reports and possible dispatch of work crews.

. Fault location: Analyzes available information to determine scope and location of fault.

. Service restoration: Determines the combination of remote control actions that will maximize restoration of service. Assists operator to dispatch work crews.

. Circuit continuity analysis: Analyzes circuit topology and device status to show electrically connected circuit segments (either energized or deenergized).

. Power factor and voltage control: Combines substation and feeder data with predetermined operating parameters to control distribution circuit power factor and voltage levels.

. Electrical circuit analysis: Performs circuit analysis, single-phase or three-phase, balanced or unbalanced.
. Load management: Controls customer loads directly through appliance switching (e.g., water heaters) and indirectly through voltage control.

. Meter reading: Reads customers’ meters for billing, peak demand studies, time of use tariffs. Provides remote connect=disconnect.


Technical Feasibility. For this kind of analysis it is important to consider at least the following points:

• System load requirements. It is important to evaluate for how long the uprated/upgraded line will satisfy the load requirements.

• Assessment of current conditions and life expectancy of transmission line materials. It is important to make this kind of evaluation for the main transmission line components, such as towers, foundations, conductors, insulators, and hardware.

• Potential margins for uprating/upgrading. It is important to check electrical clearances, mechanical strengths, ROW width, as well as the possibility of compliance with the requirements of safety codes (e.g., NESC), regulatory bodies and government agencies (e.g., navigable streams, public lands, air lanes).

• Utility considerations. Sometimes electric utilities are not authorized to take the transmission line out of service to perform the necessary uprate/upgrade services. In these cases it is important to check if the mentioned services can be done with the line in service.

Economical/Financial Feasibility. For this kind of analysis it is important to consider at least the following points:

• Uprating/upgrading costs vs. new line costs. It is important to remember that technical analysis of old lines usually requires data gathering and this can be very expensive and time consuming.

Besides that, it is necessary to estimate what will be the need of the uprated line in terms of additional ROW. Other costs that can be relevant are related to construction (material and labor), maintenance and operation of the uprated line. Environmental costs are usually higher for new lines.

• Uprating/upgrading costs vs. uprating/upgrading benefits. Environmental Feasibility. For this kind of analysis it is important to consider at least the following
• Environmental considerations. Usually not so critical when compared to new lines. However, it may be necessary to deal with historical societies, environmental groups, concerned neighbors, and so forth.

• Right-of-way easements. If significant changes will be made to the original line, it is necessary to check the validity of the previous ROW terms of use. It can be difficult to get licensing for the modified line. It is also important to check the existence of ROW encroachments and line crossings that would be unacceptable by the uprated line.


This kind of transmission line uprating can result in a much higher rating increase than thermal uprating. Besides that, transferring the same amount of power in a higher voltage level reduces the line current, and consequently, line losses and voltage drops.

However, voltage uprating is typically more expensive than thermal uprating due to the need of also uprating the voltage class of the terminal substations equipment.

Effectiveness. This kind of uprating can be a good option when: the line loading is limited by voltage drop or stability considerations; the line has margins in terms of electrical clearances; the uprating can be done with minimal line modifications or it will be applied to several circuits simultaneously, or the line design criteria can be relaxed.

Previous Analysis to Perform. Before proceeding with a transmission line voltage uprating it is necessary to analyze tower clearances, conductor-to-ground clearance, corona performance, electric fields, ROW issues, and sometimes structural strengths.

Some Usual Voltage Uprating Techniques. Some of the techniques used to perform transmission line voltage uprating are described as follows:

• Addition of insulator units to the transmission line insulator strings
• Replacement of standard insulator units by polymeric or antifog units
• Application of strut insulators (or V strings) to prevent swinging of suspension strings
• Keeping appropriate conductor-to-ground clearances while increasing the transmission line operating voltage
• Retensioning the existing conductors
•  Performing sag adjustments (cutting out conductor lengths, sliding conductor clamps)
• Increasing the conductor height at the attachment support (converting suspension strings to pseudo dead-end strings)
•  Increasing the attachment support height
•  Raising towers
• Moving towers
• Inserting additional towers
• Performing terrain contouring (rural areas)
• Bundling the original line conductor with another one, or replacing the line conductor by a bigger one, to assure a good corona performance
• Performing Line Compaction
• Converting a 3-phase double-circuit line to a 6-phase single-circuit line
• Converting a low voltage double-circuit line to a high-voltage single-circuit line
• Converting HVAC lines to HVDC lines

Some of these techniques have large structural impacts.


The construction of new substations and the expansion of existing facilities are commonplace projects in electric utilities. However, due to the complexity, very few utility employees are familiar with the complete process that allows these projects to be successfully completed.

This article will attempt to highlight the major issues associated with these capital-intensive construction projects, and provide a basic understanding of the types of issues that must be addressed during this process.

There are four major types of electric substations. The first type is the switchyard at a generating station. These facilities connect the generators to the utility grid and also provide off-site power to the plant.

Generator switchyards tend to be large installations that are typically engineered and constructed by the power plant designers and are subject to planning, finance, and construction efforts different from those of routine substation projects.

Because of their special nature, the creation of power plant switchyards will not be discussed here, but the expansion and modification of these facilities generally follow the routine processes.

Another type of substation is typically known as the customer substation. This type of substation functions as the main source of electric power supply for one particular business customer. The technical requirements and the business case for this type of facility depend highly on the customer’s requirements, more so than on utility needs, so this type of station will also not be the primary focus of this discussion.

The third type of substation involves the transfer of bulk power across the network and is referred to as a switching station. These large stations typically serve as the end points for transmission lines originating from generating switchyards, and they provide the electrical power for circuits that feed distribution stations.

They are integral to the long-term reliability and integrity of the electric system and enable large blocks of energy to be moved from the generators to the load centers. Since these switching stations are strategic facilities and usually very expensive to construct and maintain, these

The fourth type of substation is the distribution substation. These are the most common facilities in electric power systems and provide the distribution circuits that directly supply most electric customers. They are typically located close to the load centers, meaning that they are usually located in or near the neighborhoods that they supply, and are the stations most likely to be encountered by the customers.


Since all the generating units that are online have different costs of generation, it is necessary to find the generation levels of each of these units that would meet the load at the minimum cost. This has to take into account the fact that the cost of generation in one generator is not proportional to its generation level but is a nonlinear function of it.

In addition, since the system is geographically spread out, the transmission losses are dependent on the generation pattern and must be considered in obtaining the optimum pattern. Certain other factors have to be considered when obtaining the optimum generation pattern.

One is that the generation pattern provide adequate reserve margins. This is often done by constraining the generation level to a lower boundary than the generating capability. A more difficult set of constraints to consider are the transmission limits.

Under certain real-time conditions it is possible that the most economic pattern may not be feasible because of unacceptable line flows or voltage conditions. The present-day economic dispatch (ED) algorithm cannot handle these security constraints.

However, alternative methods based on optimal power flows have been suggested but have not yet been used for real-time dispatch. The minimum cost dispatch occurs when the incremental cost of all the generators is equal.

The cost functions of the generators are nonlinear and discontinuous. For the equal marginal cost algorithm to work, it is necessary for them to be convex. These incremental cost curves are often represented as monotonically increasing piecewise-linear functions.

A binary search for the optimal marginal cost is conducted by summing all the generation at a certain marginal cost and comparing it with the total power demand. If the demand is higher, a higher marginal cost is needed, and vice versa.

This algorithm produces the ideal setpoints for all the generators for that particular demand, and this calculation is done every few minutes as the demand changes.

The losses in the power system are a function of the generation pattern, and they are taken into account by multiplying the generator incremental costs by the appropriate penalty factors. The penalty factor for each generator is a reflection of the sensitivity of that generator to system losses, and these sensitivities can be obtained from the transmission loss factors.

This ED algorithm generally applies to only thermal generation units that have cost characteristics of the type discussed here. The hydro units have to be dispatched with different considerations. Although there is no cost for the water, the amount of water available is limited over a period, and the displacement of fossil fuel by this water determines its worth.

Thus, if the water usage limitation over a period is known, say from a previously computed hydro optimization, the water worth can be used to dispatch the hydro units. LFC and the ED functions both operate automatically in realtime but with vastly different time periods.

Both adjust generation levels, but LFC does it every few seconds to follow the load variation, while ED does it every few minutes to assure minimal cost. Conflicting control action is avoided by coordinating the control errors.

If the unit control errors from LFC and ED are in the same direction, there is no conflict. Otherwise, a logic is set to either follow load (permissive control) or follow economics (mandatory control).


The detailed procedure for insulation co-ordination set out in IEC 60071-1 (European standard EN60071-1 is identical) consists of the selection of a set of standard withstand voltages which characterize the insulation of the equipment of the system.

This set of withstands correspond to each of the different stresses to which the system may be subject:

• Continuous power frequency voltage (the highest voltage of the system for the life of the system).
• Slow-front overvoltage (a standard switching impulse).
• Fast-front overvoltage (a standard lightning impulse).
• Very-fast-front overvoltage (depends on the characteristics of the connected apparatus).
• Longitudinal overvoltage (a voltage between terminals combining a power frequency voltage at one end with a switching (or lightning) impulse at the other).

These voltages and overvoltages need to be determined in amplitude, shape and duration by system study. For each class of overvoltage, the analysis then determines a ‘representative overvoltage’, taking account of the characteristics of the insulation. The representative overvoltage may be characterized by one of:

• an assumed maximum,
• a set of peak values,
• a complete statistical distribution of peak values.

The next step is the determination of ‘co-ordination withstand’ voltages – the lowest values of the withstand voltages of the insulation in use which meet the system or equipment performance criteria when subjected to the ‘representative overvoltages’ under service conditions.

Factors are then applied to compensate for:

• the differences in equipment assembly,
• the dispersion of the quality of the products within the system,
• the quality of installation,
• the ageing of installation during its lifetime,
• atmospheric conditions,
• contingency for other factors.

This results in so-called ‘required withstand voltages’ – test voltages that must be withstood in a standard withstand test. In specifying equipment the next step is then to specify a standard test withstand voltage (a set of specific test voltages is provided in IEC 60071-1) which is the next above the required withstand voltage, assuming the same shape of test voltage.

A test conversion factor must be applied to the required withstand voltage if the test voltage is of a different shape to the class of overvoltage in question. Figure 9.6 sets this procedure out in diagrammatic form, and full details of what is involved with each step is provided in IEC 60071.


An advanced energy storage technology is superconducting magnetic energy storage (SMES), which may someday allow electric utilities to store electricity with unparalled efficiency (90% or more).

A simple description of SMES operation follows.

The electricity storage medium is a doughnut-shaped electromagnetic coil of superconducting wire. This coil could be about 1000 m in diameter, installed in a trench, and kept at superconducting temperature by a refrigeration system.

Off-peak electricity, converted to direct current (DC), would be fed into this coil and stored for retrieval at any moment. The coil would be kept at a low-temperature superconducting state using liquid helium.

The time between charging and discharging could be as little as 20 ms with a round-trip AC–AC efficiency of over 90%.

Developing a commercial-scale SMES plant presents both economic and technical challenges. Due to the high cost of liquiud helium, only plants with 1000-MW, 5-h capacity are economically attractive.

Even then the plant capital cost can exceed several thousand dollars per kilowatt. As ceramic superconductors, which become superconducting at higher temperatures (maintained by less expensive liquid nitrogen), become more widely available, it may be possible to develop smaller scale SMES plants at a lower price.


When a conductor is covered with ice and/or is exposed to wind, the effective conductor weight per unit length increases. During occasions of heavy ice and/or wind load, the conductor catenary tension increases dramatically along with the loads on angle and deadend structures. Both the conductor and its supports can fail unless these high-tension conditions are considered in the line design.

Certain utilities in very heavy ice areas use glaze ice thickness of as much as 2 in (50 mm) to calculate iced conductor weight. Similarly, utilities in regions where hurricane winds occur may use wind loads as high as 34 lb/ft2 (1620 Pa).

As the NESC indicates, the degree of ice and wind loads varies by region. Some areas may have heavy icing, whereas some areas may have extremely high winds. The loads must be accounted for in the line design process to prevent a detrimental effect on the line.

Some of the effects of both the individual and combined components of ice and wind loads are discussed below:

Ice loading of overhead conductors may take several physical forms (glaze ice, rime ice, or wet snow). The impact of lower-density ice formation is usually considered in the design of line sections at high altitudes.

The formation of ice on overhead conductors has the following influence on line design:

• Ice loads determine the maximum vertical conductor loads that structures and foundations must withstand.
• In combination with simultaneous wind loads, ice loads also determine the maximum transverse loads on structures.
• In regions of heavy ice loads, the maximum sags and the permanent increase in sag with time (difference between initial and final sags) may be due to ice loadings.

Ice loads for use in designing lines are normally derived on the basis of past experience, code requirements, state regulations, and analysis of historical weather data. Mean recurrence intervals for heavy ice loadings are a function of local conditions along various routings.

The impact of varying assumptions concerning ice loading can be investigated with line design software. The calculation of ice loads on conductors is normally done with an assumed glaze ice density of 57 lb/ft3 (8950 N/m3).

The weight of ice per unit length is calculated with the following equation: Wice = 0.0281t(Dc +  t)  where
 t = radial thickness of ice, mm
Dc = conductor outside diameter, mm
Wice = resultant weight of ice, N/m

The ratio of iced weight to bare weight depends strongly on conductor diameter. As shown in Table 14-16, for three different conductors covered with 0.5-in radial glaze ice, this ratio ranges from 4.8 for No. 1/0 AWG wire to 1.6 for 1590-kcmil conductors.

As a result, small-diameter conductors may need to have a higher elastic modulus and higher tensile strength than do large conductors in heavy ice and wind loading areas to limit sag.


The electrical operating performance of a transmission line depends primarily on the insulation. An insulator not only must have sufficient mechanical strength to support the greatest loads of ice and wind that may be reasonably expected, with an ample margin, but must be so designed as to withstand severe mechanical abuse, lightning, and power arcs without mechanically failing.

It must prevent a flashover for practically any power-frequency operating condition and many transient voltage conditions, under any conditions of humidity, temperature, rain, or snow, and with such accumulations of dirt, salt, and other contaminants that are not periodically washed off by rains.

Insulator Standards. The NEMA Publication High Voltage Insulator Standards, and AIEE Standard 41 have been combined in ANSI C29.1 through C29.9. Standard C29.1 covers all electrical and mechanical tests for all types of insulators.

The standards for the various insulators covering flashover voltages; wet, dry, and impulse; radio influence; leakage distance; standard dimensions; and mechanical-strength characteristics are as follows:

C29.2, suspension; C29.3, spool; C29.4, strain; C29.5, low- and medium-voltage pin; C29.6, high-voltage pin; C29.7, high-voltage line post; C29.8, apparatus pin; C29.9, apparatus post. These standards should be consulted when specifying or purchasing insulators.


Overhead transmission of electric power remains one of the most important elements of today’s electric power system. Transmission systems deliver power from generating plants to industrial sites and to substations from which distribution systems supply residential and commercial service.

Those transmission systems also interconnect electric utilities, permitting power exchange when it is of economic advantage and to assist one another when generating plants are out of service because of damage or routine repairs. Total investment in transmission and substations is approximately 10% of the investment in generation.

Since the beginning of the electrical industry, research has been directed toward higher and higher voltages for transmission. As systems have grown, higher-voltage systems have rarely displaced existing systems, but have instead overlayed them.

Economics have typically dictated that an overlay voltage should be between 2 and 3 times the voltage of the system it is reinforcing. Thus, it is common to see, for example, one system using lines rated 115, 230, and 500 kilovolts (kV).

The highest ac voltage in commercial use is 765 kV although 1100 kV lines have seen limited use in Japan and Russia. Research and test lines have explored voltages as high as 1500 kV, but it is unlikely that, in the foreseeable future, use will be made of voltages higher than those already in service.

This plateau in growth is due to a corresponding plateau in the size of generators and power plants, more homogeneity in the geographic pattern of power plants and loads, and adverse public reaction to overhead lines.

Recognizing this plateau, some focus has been placed on making intermediate voltage lines more compact. Important advances in design of transmission structures as well as in the components used in line construction, particularly insulators, were made during the mid-1980s to mid-1990s.

Current research promises some further improvements in lines of existing voltage including uprating and now designs for HVDC.


A SCADA system consists of a master station that communicates with remote terminal units (RTUs) for the purpose of allowing operators to observe and control physical plants. Generating plants and transmission substations certainly justify RTUs, and their installation is becoming more common in distribution substations as costs decrease. RTUs transmit device status and measurements to, and receive control commands and setpoint data from, the master station.

Communication is generally via dedicated circuits operating in the range of 600 to 4800 bits=s with the RTU responding to periodic requests initiated from the master station (polling) every 2 to 10 s, depending on the criticality of the data.

The traditional functions of SCADA systems are summarized:
. Data acquisition: Provides telemetered measurements and status information to operator.
. Supervisory control: Allows operator to remotely control devices, e.g., open and close circuit breakers. A ‘‘select before operate’’ procedure is used for greater safety.
. Tagging: Identifies a device as subject to specific operating restrictions and prevents unauthorized operation.
. Alarms: Inform operator of unplanned events and undesirable operating conditions. Alarms are sorted by criticality, area of responsibility, and chronology. Acknowledgment may be required.
. Logging: Logs all operator entry, all alarms, and selected information.
. Load shed: Provides both automatic and operator-initiated tripping of load in response to system emergencies.
. Trending: Plots measurements on selected time scales.

Since the master station is critical to power system operations, its functions are generally distributed among several computer systems depending on specific design. A dual computer system configured in primary and standby modes is most common.

SCADA functions are listed below without stating which computer has specific responsibility.

. Manage communication circuit configuration
. Downline load RTU files
. Maintain scan tables and perform polling
. Check and correct message errors
. Convert to engineering units
. Detect status and measurement changes
. Monitor abnormal and out-of-limit conditions
. Log and time-tag sequence of events
. Detect and annunciate alarms
. Respond to operator requests to:

– Display information
– Enter data
– Execute control action
– Acknowledge alarms
. Transmit control action to RTUs
. Inhibit unauthorized actions
. Maintain historical files
. Log events and prepare reports
. Perform load shedding


Industry standards dictate certain analytical techniques that adhere to specific guidelines, suited to address the questions of ac and dc decrement in multimachine systems in compliance with well-established, industry-accepted practices.

They are also closely linked to and harmonize quite well with existing switchgear rating structures. Typical standards are the North American ANSI and IEEE C37 standards and recommended practices the international standard, IEC 60909 (1988) and others, such as the German VDE 0102-1972 and the Australian AS 3851-1991.

The analytical and computational framework in the calculating procedures recommended by these standards remains algebraic and linear, and the calculations are kept tractable by hand for small systems.

The extent of the data base requirements for computer-based solutions is carefully kept to a necessary maximum for the results to be acceptably accurate. This type of analysis represents the best compromise between solution accuracy and simulation simplicity.

The great majority of commercialgrade short-circuit analysis programs fall under this category. In 7.4.1, an outline of ANSI and IEEE standards is presented, while in 7.4.2, the relevant aspects of IEC 60909 (1988) are described. It is not the intent of these subclauses to fully explore and describe in detail all pertinent clauses of either standard.

Instead, a rather brief summary is presented in an effort to make any potential user conscious of the salient aspects of each technique. Because only a brief summary is presented, it is strongly recommended that the standards be consulted for further clarifications and details.


The test is made by running the machine as a motor at rated voltage and frequency without connected load. To ensure that the correct value of friction loss is obtained, the machine should be operated until the input has stabilized.

5.3.1 No-load current
The current in each line is read. The average of the line currents is the no-load current.

5.3.2 No-load losses
The reading of input power is the total of the losses in the motor at no-load. Subtracting the stator I2R
loss (at the temperature of this test) from the input gives the sum of the friction (including brush friction loss on wound-rotor motors), windage, and core losses.

5.3.3 Separation of core loss from friction and windage loss
Separation of the core loss from the friction and windage loss may be made by reading voltage, current, and power input at rated frequency and at voltages ranging from 125% of rated voltage down to the point where further voltage reduction increases the current.

5.3.4 Friction and windage
Power input minus the stator I2R loss is plotted vs. voltage, and the curve so obtained is extended to zero voltage. The intercept with the zero voltage axis is the friction and windage loss.

The intercept may be determined more accurately if the input minus stator I2R loss is plotted against the voltage squared for values in the lower voltage range. An example is the dashed curve shown in figure 1.

5.3.5 Core loss
The core loss at no load and rated voltage is obtained by subtracting the value of friction and windage loss (obtained from 5.3.4) from the sum of the friction, windage loss, and core loss (obtained from 5.3.2).


What Are Corona Probe Tests For Rotating Machines?

The corona-probe test is intended to be an indicator and locator of unusual ionization about the insulation structure. This test is sensitive to end-winding surface corona, as well as internal-cavity ionization in the insulation structure.

Compared to slot discharge, the discharge energies involved in surface corona or internal-cavity ionization may be of a much lower order of magnitude. The energy in the discharge varies as the square of the voltage across the gap and directly as the effective capacitance at the point of breakdown.

Partial Discharge (Corona) has several undesirable effects, such as chemical action, production of heat, and ionic bombardment. The deteriorating effects of corona are dependent on its intensity and repetition rate as well as the design of the insulation system involved.

Inorganic insulation components such as mica and glass are not affected seriously by corona. Charring or decomposition of organic materials will occur in the vicinity of continued corona activity.

However, surface effects may be limited by insulating finish treatments incorporating pigmentation to resist attack from the weak acid deposits formed by surface corona in the presence of oxygen and moisture.

Corona-probe-test equipment consists of three basic units:

1) Equipment capable of energizing the stator winding at its normal operating line-to-neutral voltage at rated frequency.

2) An antenna or corona probe. For end-winding corona measurement, the antenna usually about 1 in long, surrounded by an insulation housing, and mounted on the end of a long insulating handle.

For internal-cavity-discharge (corona) measurements, these utilize a multiturn coil wound on a ferrite rod approximately 2 in long by 0.25 in diameter and mounted on the end of an insulating handle. Measurements are made by placing the ferrite rod over the teeth enclosing the coil being tested.

3) An amplifier and indicator (for connection to the antenna) or a peak-pulse meter (for connection to the ferrite corona probe). The amplifier is one of the usual type for audio frequencies and must reject 60 Hz and radio frequency signals. The indicator may be earphones, an output meter, or a cathode-ray oscilloscope.

The peak-pulse meter is a broadband instrument calibrated in units of picocoulombs of apparent charge. Measurements may be obtained from the meter itself or by connecting the meter output to an oscilloscope or chart recorder.

The use of the corona-probe test and the evaluation of test data obtained is in relatively early stages of development and study. The ability of the test to distinguish varying intensities of external corona activity and internal cavity corona has been established.

However, the evaluation of data, to permit discrimination between harmful and acceptable levels, has not yet reached the stage where industry standards are established.


Overvoltage tests are used to obtain assurance concerning the minimum strength of the insulation. Such tests are made on all or parts of the ground insulation.

Many users of large rotating machines apply overvoltage tests periodically, generally at the beginning of the overhaul of related equipment. This allows for the detection and possible repair of insulation weaknesses during the scheduled outage.

An overvoltage test should be applied to each phase separately with the remaining phases not under test being grounded. In this way, the insulation between phases (or lines) is also tested. This is only practical, however, where both ends of each phase are brought out to separate terminals, as is usually the case in generators.

Some motors may have three or four leads brought out which precludes test between phases. Overvoltage tests may be performed either with alternating or direct voltage. The level of overvoltage which should be applied will depend to a large extent on the type and age of the machine involved, the degree of exposure to overvoltages, and the level of serviceability required from the machine in question.

It should, however, be sufficiently searching to discern any weakness or incipient weakness in the insulation structure which might lead to service failure. It should be recognized that if the windings are clean and dry, overvoltage tests may not detect defects which are in the end turns or in leads remote from the stator core.

The values of test voltages usually are selected in the range of 125 to 150% of the rated line-to-line voltage and are normally held for 1 min:

1) Refer to IEEE Std 4-1968 , Techniques for Dielectric Tests (ANSI C68.1-1968 ), for power frequency testing

2) Refer to IEEE Std 433-1974 , Recommended Practice for Insulation Testing of Large AC Rotating Machinery with High Voltage at Very Low Frequency, for 0.1 Hz testing and recommended voltage level ratio

3) Refer to IEEE 95-1977 for direct voltage testing and recommended voltage level ratio


As has been stated, electrical machines and their insulation systems are subjected to mechanical, electrical, and thermal stresses which give rise to many deteriorating influences, the most significant of which are the following.

4.1 Thermal Aging
Gradual aging caused by temperatures due to normal operating loads.

4.2 Overtemperature
Unusually high temperature from causes such as overload, high ambient temperature, restricted ventilation, and loss of cooling liquid.

4.3 Overvoltage
Unusually high voltage such as from switching or lightning surges.

4.4 Contamination
This deteriorates electrical insulation by actually conducting current over insulated surfaces, or by attacking the material reducing its electrical insulating quality or its physical strength, or by thermally insulating the material forcing it to operate at higher than normal temperatures. Included here are:

Wetness or extreme humidity
Oil or grease
Conducting dusts and particles
Nonconducting dusts and particles
Chemicals of industry

4.5 Physical Damage
This contributes to electrical insulation failure by opening leakage paths through the insulation. Included here are:

Physical shock
Unusual electromagnetic forces Erosion by foreign matter
Damage by foreign objects
Thermal cycling

4.6 Partial Discharge (Corona) Effects
Partial discharges which may occur at higher operating voltages may be accompanied by several undesirable effects such as chemical action, heating, and ionic bombardment.


Structure Types – the following descriptions of structure types shall apply to the provisions for strength requirements:

Suspension Structure – A structure where the phase conductors and static wires are attached through the use of suspension insulators and hardware or, in the case of the static wire, with a clamp not capable of resisting the full design tension of the wire.

Strain Structure – A structure where the phase conductors and static wires are attached to the structure by use of dead-end insulators and hardware but where the ability of the structure to resist a condition where all wires are broken on one side under full loading is not required or desired.

Typically, strain structures would be used where the line deflection angle is 45 degrees or less. Structures subject to strain structure requirement shall be as identified by the Utility.

Dead-end Structure - A structure where the phase conductors and static wires are attached to the structure by use of dead-end insulators and hardware and where the ability of the structure to resist a condition where all wires are broken on one side under full loading is required or desired.

Typically, dead-end structures would be used where the line deflection angle is greater than 45 degrees. Structures subject to dead-end structure requirement shall be as identified by the Utility.

Line Termination Structure – A structure where the phase conductors and static wires are to be installed on one side only for the purpose of terminating the line, usually at a substation or switchyard.

This permanent dead-end condition is assumed in the application of all applicable loading conditions.


Because the neutral conductor carries less current than the phase conductors, utilities can use smaller neutral conductors. On three-phase circuits with balanced loading, the neutral carries almost no current.

On single-phase circuits with a multigrounded neutral, the neutral normally carries 40 to 60% of the current (the earth carries the remainder).

On single-phase circuits, some utilities use fully rated neutrals, where the neutral and the phase are the same size. Some use reduced neutrals.

The resistance of the neutral should be no more than twice the resistance of the phase conductor, and we are safer with a resistance less than 1.5 times the phase conductor, which is a conductivity or cross-sectional area of 2/3 the phase conductor.

Common practice is to drop one to three gage sizes for the neutral: a 4/0 phase has a 2/0 neutral, or a 1/0 phase has a number 2 neutral. Dropping three gage sizes doubles the resistance, so we do not want to go any smaller than that.

On three-phase circuits, most utilities use reduced neutrals, dropping the area to about 25 to 70% of the phase conductor (and multiplying the resistance by 1.4 to 4).

Several other factors besides ampacity play a role in how small neutral conductors are:

• Grounding — A reduced neutral increases the overvoltages on the unfaulted phases during single line-to-ground faults. It also increases stray voltages.

• Faults — A reduced neutral reduces the fault current for single line to- ground faults, which makes it more difficult to detect faults at far distances. Also, the reduced neutral is subjected to the same fault current as the phase, so impacts on burning down the neutral should be considered for smaller neutrals.

• Secondary — If the primary and secondary neutral are shared, the neutral must handle the primary and secondary unbalanced current (and have the mechanical strength to hold up the secondary phase conductors in triplex or quadraplex construction).

• Mechanical — On longer spans, the sag of the neutral should coordinate with the sag of the phases and the minimum ground clearances to ensure that spacing rules are not violated.
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