Different categories of harmonic-producing loads are supplied by the electric utilities such as

1. Domestic loads like fluorescent lamps, light dimmers, etc.

2. Ripple control systems for regulating hot-water loads

3. Medium-sized industrial loads like several adjustable speed drives in a cement mill, paper mill, etc.

4. Large loads like high-voltage direct current (HVDC) convertors, aluminum smelters, static var compensators, heavy single-phase ac traction loads for hauling coal trains, etc.

The undesirable effects of the harmonics produced by these loads are listed as follows:1–3
1. Capacitors: These may draw excessive current and prematurely fail from increased dielectric loss and heating. Also, under resonance conditions, considerably higher voltages and currents can be observed than would be the case without resonance.

IEEE Std 18-19924 gives limits on voltage, current, and reactive power for capacitor banks based on their ratings. These can be used to determine the maximum allowable harmonic levels.

2. Power Cables: In systems with resonant conditions, cables may be subjected to voltage stress and corona, which can lead to dielectric (insulation) failure. Further harmonic currents can cause heating.

3. Telephone Interference: Harmonics can interfere with telecommunication systems, especially noise on telephone lines. A “standard” human ear in combination with a telephone set has a sensitivity to audio frequencies that peaks at about 1 kHz.

Two systems with slightly different weighting systems are used to obtain a reasonable indication of the interference from each harmonic. The two systems are:

C-message weighting by Bell Telephone system (BTS) and Edison Electric Institute used in the United States and Canada

Psophometric weighting by the International Consultative Commission on Telephone and Telegraph System


The distribution of the armature windings and the presence of slots in the machines cause spatial harmonics in them. These in turn produce time harmonics in the induced voltages, which appear at the terminals.

Most of the power station generators are wye-connected. In such machines, triplen harmonic voltages do not appear in line-to-line voltages. Also, triplen harmonics can be eliminated even in phase-to-neutral voltages by using two-third pitch winding.

Usually, the most significant harmonics to be minimized by the use of fractional pitch windings are the fifth and seventh. Higher harmonics than the ninth are so small that they require little attention except in rare cases.

Voltage flicker is caused by arc furnace loads at the point of common coupling. For steel making, arc furnaces of the rating 100 MW and above are used.

Usually, a melting cycle can be divided into three distinct steps—drilling period, melting period, and reheating period. The full voltage is applied during the melting period, and the time required for melting is rather large compared with other steps.

Due to uneven arc length, the bus voltage fluctuates continuously during the melting cycle. For large arc furnaces, reactive voltage controllers such as SVCs are required to keep the voltage within the specified limits.

1. Kimbark, E.W., Direct Current Transmission (1971). Vol. 1, John Wiley, New York.
2. Schlabbach, J., Blume, D., and Stephanblome, T. (2001). Voltage Quality in Electrical
Power Systems, IEE, London.
3. Mahmoud, Aly A. (1984). Power System Harmonics: An Assessment. IEEE Tutorial
Course Text, EHO221-2-PWR, 1–9.
4. Arrillaga, J., Bradley, J.D., and Bodger, P. (1985). Power System Harmonics, John
Wiley, Chichester, U.K.
5. Arrillaga, J. and Watson, N.R. (2003). Power System Harmonics, John Wiley,
Chichester, U.K.
6. Adamson, C. and Hingorani, N.G. (1960) High Voltage Direct Current Power Transmission,
Chapter 3, Garraway, London.
7. Dugan, R.C., McGranaghan, M.G., and Beaty, H.W., (1996). Electrical Power Systems
Quality, McGraw-Hill, New York.
8. Feature Article: “Reducing the Safety Hazard of Switchers,” Electronics Australia,
February 1990, 124–125.


Because transformer cores are made of ferromagnetic materials, the exciting current of the transformer under no-load conditions is not sinusoidal even though the applied voltage and flux are sinusoidal due to the nonlinear nature of the B-H curve, and similarly the relationship between flux and magnetomotive force (MMF).

For anyvalue of flux, there are two values of MMF, depending on whether the flux is increasing or decreasing. From these MMFs, the magnetizing current can be computed and plotted corresponding to these values of flux, depending on whether the flux is rising or falling.

With three-limb transformers, as the triplen harmonics return through air (or rather through oil and tank), the higher reluctance of the path reduces the third harmonics to a lower value (about 10% of the value in independent core phases). The fifth and seventh harmonics may also be large enough, around 5–10%.

The transient current drawn by a transformer when it is first energized depends upon the instant of switching. If the transformer is energized when the applied sinusoidal voltage is at its peak, usually there is no transient.

If the transformer is energized when the applied voltage is zero and it has a residual flux fr with unfavorable polarity, then the total flux that would be required to counteract the applied voltage according to Lenz’s law would be 2 fm + fr.

To produce such a flux, the transformer may have to draw many times (say, 100 times) the normal exciting current of the transformer. In actual practice, the inrush current may be 8 to 10 times the full-load current of the transformer, depending upon the instant of switching and polarity of the applied voltage.

Depending upon the transformer, the inrush current phenomenon may persist for a few seconds, thus creating harmonics during this period.

Under unbalanced conditions, the transformer excitation current can contain odd and even harmonics. The transformers feeding half-wave rectifiers or supplying power to a three-phase converter with unbalanced firing fall into this category.

The magnitude of the harmonic components of the excitation current in the presence of the direct current on the secondary side of the transformer increase almost linearly with the dc content. The linearity is better for the lower-order harmonics.

As the harmonics generated by the transformer under dc magnetization are largely independent of the ac excitation, there appears to be no advantage in designing a transformer to run “underfluxed” in the presence of direct current.


Until now, the use of the some control diagram was only possible for motors fed from a low-voltage network due to the lack of technical and economic solutions acceptable for the medium-voltage zone.

Currently, these solutions exist, and therefore the medium-voltage motors too can be fed directly with variable frequency voltage. Existing installations for medium-voltage motors supplied with variable frequency use an intermediate reduced voltage circuit and an increased frequency converter outlet voltage (Figure 1.11).

Transformer T2 operation at variable frequency requires the magnetic induction to be kept at a value that should not exceed the saturation limit.

As in the case of the asynchronous machine, to keep the induction equal to the rated induction, for frequencies under the rated frequency it is necessary to meet the condition between the terminal voltage and supply voltage frequency.

In the specific case shown in Figure 1.11, the condition is met, being required by the asynchronous motor operation. Obviously, the condition  has to be met by the transformers of another type that can operate at frequencies other than the rated frequency.

One case often met is that where pieces of equipment are designed for 60 Hz operating systems. Their utilization in 50 Hz frequency systems requires the supply voltage to be reduced some 20% against their rated voltage.

The pieces of equipment with magnetic circuits designed to operate both to 50 Hz and 60 Hz have larger losses with the 50 Hz supply. For low-power equipment the losses are irrelevant.

For equipment of larger power it is required to consider operation at reduced frequency. Identically, the utilization of parallel-connected coils, at a frequency other than the rated frequency, requires analysis of the conditions when saturation limits are exceeded and losses increase.

Induction keeping to the rated value requires control of the voltage to terminals.


IEEE Standards are publications that provide acceptable design practice. IEEE Standards addressing power quality include those defining acceptable power quality (IEEE Standard 519) and another standard relating to the measurement of power-quality “events” (IEEE Standard 1159).

Both of these standards focus on AC systems and their harmonics (that is, multiples of the line frequency). IEEE Standard 519 [2.1] (denoted IEEE Std. 519-1992) is titled “IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems.”

The abstract of this standard notes that power conversion units are being used today in industrial and commercial facilities, and there are challenges associated with harmonics and reactive power control of such systems. The standard covers limits to the various disturbances recommended to the power distribution system.

The 1992 standard is a revision of an earlier IEEE work published in 1981 covering harmonic control. The basic themes of IEEE Standard 519 are twofold. First, the utility has the responsibility to produce good quality voltage sine waves.Secondly, end-use customers have the responsibility to limit the harmonic currents their circuits draw from the line.

Shown in Figure 2.1 is a utility system feeder serving two customers. The utility source has resistance R and line reactance jXs. The resistance and reactance model the impedances of the utility source, any transformers and switchgear, and power cabling.

Figure 2.1 Harmonic-generating load causing voltage distortion at the point of common coupling (PCC). The AC source is modeled as an ideal voltage source in series with a resistance Rs and a reactance jXs.

Customer #1 on the line draws harmonic current Ih, as shown, perhaps by operating adjustable speed drives, arc furnaces, or other harmonic-creating systems. The voltage Customer #2 sees at the service entrance is the voltage at the “point of common coupling,” often abbreviated as “PCC.” The harmonics drawn by Customer #1 cause voltage distortion at the PCC, due to the voltage drop in the line resistance and reactance due to the harmonic current.

The voltage harmonic distortion limits apply to the quality of the power the utility must deliver to the customer. For instance, for systems of less than 69 kV, IEEE 519 requires limits of 3 percent harmonic distortion for an individual frequency component and 5 percent for total harmonic.

The current harmonic distortion limits apply to limits of harmonics that loads should draw from the utility at the PCC. Note that the harmonic limits differ based on the ISC/IL rating, where ISC is the maximum short-circuit current at the PCC, and IL is the maximum demand load current at the PCC. IEEE Standard 1159 [2.2] is entitled “IEEE Recommended Practice for Monitoring Electric Power Quality,” and as its title suggests, this standard covers recommended methods of measuring power quality events.

Many different types of power-quality measurement devices exist and it is important for workers in different areas of power distribution, transmission, and processing to use the same language and measurement techniques. In future chapters, we draw extensively from IEEE Standards 519 and 1159. distortion.


PWM is used in inverters to supply power to the ac motors more commonly in the industry now. In PWM, a sawtooth wave is used to modulate the chops as shown in Figure 4.8.

FIGURE 4.8 The principle of pulse-width modulation (PWM). (From Arrillaga, J., Bradley, J.D., and Bodger, P. (1985), Power System Harmonics, John Wiley, Chichester, U.K. With permission.)

The sawtooth wave has a frequency that is a multiple of three times the sine-wave frequency, allowing symmetrical three-phase voltages to be generated from a three phase sine-wave set and one sawtooth waveform. The PWM control signal is generated by feeding the sawtooth carrier signal and sine-wave modulating signal to a comparator circuit. In this simple form, this method controls line-to-line voltage from zero to full voltage by increasing the magnitude of the sawtooth, with little regard to the harmonics generated.

More efficient PWM techniques have been developed to control the fundamental and harmonic voltages simultaneously. Using suitable switching times with five on/off actions per cycle, one can eliminate both fifth and seventh harmonics together.

Generally, at any fundamental switching frequency, each chop per half-cycle of the inverter phase voltage waveform can eliminate one harmonic of the waveform or reduce a group of harmonic amplitudes. Assuming that there are m chops per half-cycle, one chop can be utilized to control the fundamental voltage and the other (m - 1) to reduce the other specified low-order harmonics or to minimize power losses caused by a specified range of harmonics within the motors.

However, it must be noted that, as the total rms harmonic voltage cannot change, the portion of the rms voltage that was provided by the elimination of harmonics will be spread over the remaining harmonic magnitudes. Hence, the motor designer must take this fact into account.

Also, the integrating filter characteristic of the motor will reduce some of these higher-order-current harmonics. Because of the number of switchings, the usable fundamental rating and the converter efficiency are reduced as GTOs require significant energy (resulting in increased thyristor losses and heating effects) for each switching operation.

In contrast, devices such as IGBTs (Integrated state Bipolar Transistors) and IGCTs (Integrated State Commutated Thyrestors) require much lower switching energy and are better suited to the use of PWM techniques. However, with the use of chain circuits that require reduced switching frequency, that is, once per two cycles of frequency, high-power inverters can be constructed using GTOs.


Before specifying the compensators, compensator and system details, and operation and maintenance requirements must be specified. Some of the important items are listed in the following text even though this list is not comprehensive.

a. System details
1. System frequency variation under normal operating conditions, fault conditions, and generator outage conditions

2. Voltage regulation that is required and its precision

3. Maximum harmonic distortion with the compensator in service

4. Coordination of system protection with compensator protection and reactive power limits

5. Compensator energization details, including any necessary precautions

b. Compensator details
1. Maximum continuous reactive power requirements: capacitive and inductive

2. Overload rating and duration

3. Normal-rated voltage and limits of voltage between which the reactive power ratings must not be exceeded

4. Response times of the compensator for different system disturbances

5. Control requirements

6. Reliability and redundancy of components

c. Operation, maintenance, and installation requirements
1. Spare parts, provision for future expansion

2. Performance with unbalanced voltages or with unbalanced load

3. Cabling details, access, enclosure, and grounding


To develop compatibility levels and to deepen the understanding of system performance, data on power quality are being collected by various agencies from around the world. Some of these organizations are Electrical Power Research Institute (EPRI), Canadian Electrical Association, National Power Laboratories (Necedah, Wisconsin), Norwegian Electric Power Research Institute, International Union of Producers and Distributors of Electrical Energy (UNIPEDE), Electricite de France, Northeast Utilities Service (Berlin, Connecticut), East Midlands Electricity (EME, Nottingham, England), and Consolidated Edison Company of New York, Inc.

Because of reasons of cost, power quality monitoring is still in its infancy. However, as a result of deregulation in the utility industry in many countries, they will be forced to compete for customers.

One of the ways in which they can achieve this is by monitoring power quality and showing the customers that their power supply reliability is better than that of their competitors. Hence, utilities on their own are likely to undertake more monitoring of the feeders supplying their major customers. The data required to monitor power quality are usually voluminous.

Hence, software must be used to automatically characterize measured events and store the results in a well-defined database. It will be economical to integrate the data collected from power quality and in plant monitoring with electric power instrumentation, site descriptions, and event information. For details of a power quality database management and analysis system called PQView, developed by Electrotek Concepts, Inc. (Knoxville, Tennessee).

Over the last several years, the EPRI and one of its contractors (Electrotek Concepts, Inc.) have been developing a vendor-independent interchange format for power quality-related information. For the details of this Power Quality Data Interchange Format (PQDIF), PQView, and PQWeb systems.

In 1996, EPRI and Electrotek placed PQDIF in the public domain to facilitate the interchange of power quality data between interested parties. EPRI and Electrotek have also offered the format, sample source code, and documentation to the IEEE 1159.3 task force as a possible initial format to meet that group’s requirements.

In 1991, the Power System Relaying Committee of the IEEE Power Engineering Society developed the standard C37.111.39 The main purpose of this standard was to define a common format for the data files and exchange medium needed for the interchange of various types of fault, test, or simulation data.

Among others, the standard defines as sources of data the following: digital fault recorders, analog tape recorders, digital protective relays, transient simulation programs, and analog simulators. For the details of indices for assessing the harmonic distortion of power quality, D. Daniel Sabin et al.

A power quality database can provide a basis for developing equipment compatibility specifications and guidelines for future equipment enhancements. In addition, a database of the causes for recorded disturbances can be used to make system improvements.

By ensuring equipment compatibility, safety hazards resulting from equipment misoperation or failure can be avoided. Performance indices that measure system reliability in terms of voltage outages are defined in a document (Reference 31) prepared by the EPRI, Palo Alto, California.


The voltage sag performance for a given customer facility will depend on whether the customer is supplied from the transmission system or from the distribution system. For a customer supplied from the transmission system, the voltage sag performance will depend on only the transmission system fault performance.

On the other hand, for a customer supplied from the distribution system, the voltage sag performance will depend on the fault performance on both the transmission and distribution systems. Transmission line faults and the subsequent opening of the protective devices rarely cause an interruption for any customer because of the interconnected nature of most modern-day transmission networks.

These faults do, however, cause voltage sags. Depending on the equipment sensitivity, the unit may trip off, resulting in substantial monetary losses. The ability to estimate the expected voltage sags at an end-user location is therefore very important. Most utilities have detailed short-circuit models of the interconnected transmission system available for programs such as ASPEN*

One Liner.These programs can calculate the voltage throughout the system resulting from faults around the system. Many of them can also apply faults at locations along the transmission lines to help calculate the area of vulnerability at a specific location.

The area of vulnerability describes all the fault locations that can cause equipment to misoperate. The type of fault must also be considered in this analysis. Single-line-to-ground faults will not result in the same voltage sag at the customer equipment as a three-phase fault.

The characteristics at the end-use equipment also depend on how the voltages are changed by transformer connections and how the equipment is connected, i.e., phase-to-ground or phase-to-phase. Table 3.1 summarizes voltages at the customer transformer secondary for a single- line-to-ground fault at the primary.

TABLE 3.1 Transformer Secondary Voltages with a Single-Line-to-Ground Fault on the Primary

The relationships in Table 3.1 illustrate the fact that a single-line to- ground fault on the primary of a delta-wye grounded transformer does not result in zero voltage on any of the phase-to-ground or phase to-phase voltages on the secondary of the transformer.

The magnitude of the lowest secondary voltage depends on how the equipment is connected:

■ Equipment connected line-to-line would experience a minimum voltage of 33 percent.
■ Equipment connected line-to-neutral would experience a minimum voltage of 58 percent.

This illustrates the importance of both transformer connections and the equipment connections in determining the actual voltage that equipment will experience during a fault on the supply system.

Math Bollen16 developed the concept of voltage sag “types” to describe the different voltage sag characteristics that can be experienced at the end-user level for different fault conditions and system configurations.

The five types that can commonly be experienced are illustrated in Fig. 3.8. These fault types can be used to conveniently summarize the expected performance at a customer location for different types of faults on the supply system.

The actual expected performance is then determined by combining the area of vulnerability with the expected number of faults within this area of vulnerability. The fault performance is usually described in terms of faults per 100 miles/year (mi/yr). Most utilities maintain statistics of fault performance at all the different transmission voltages.

These system wide statistics can be used along with the area of vulnerability to estimate the actual expected voltage sag performance. The figure shows the expected number of voltage sags per year at the customer equipment due to transmission system faults.

The performance is broken down into the different sag types because the equipment sensitivity may be different for sags that affect all three phases versus sags that only affect one or two phases.


Equipment within an end-user facility may have different sensitivity to voltage sags. Equipment sensitivity to voltage sags is very dependent on the specific load type, control settings, and applications. Consequently, it is often difficult to identify which characteristics of a given voltage sag are most likely to cause equipment to misoperate.

The most commonly used characteristics are the duration and magnitude of the sag. Other less commonly used characteristics include phase shift and unbalance, missing voltage, three-phase voltage unbalance during the sag event, and the point-in-the-wave at which the sag initiates and terminates.

Generally, equipment sensitivity to voltage sags can be divided into three categories:

■ Equipment sensitive to only the magnitude of a voltage sag. This group includes devices such as undervoltage relays, process controls, motor drive controls,6 and many types of automated machines (e.g., semiconductor manufacturing equipment).

Devices in this group are sensitive to the minimum (or maximum) voltage magnitude experienced during a sag (or swell). The duration of the disturbance is usually of secondary importance for these devices.

■ Equipment sensitive to both the magnitude and duration of a voltage sag. This group includes virtually all equipment that uses electronic power supplies. Such equipment misoperates or fails when the power supply output voltage drops below specified values.

Thus, the important characteristic for this type of equipment is the duration that the rms voltage is below a specified threshold at which the equipment trips.

■ Equipment sensitive to characteristics other than magnitude and duration. Some devices are affected by other sag characteristics such as the phase unbalance during the sag event, the point-in-thewave at which the sag is initiated, or any transient oscillations occurring during the disturbance.

These characteristics are more subtle than magnitude and duration, and their impacts are much more difficult to generalize. As a result, the rms variation performance indices defined here are focused on the more common magnitude and duration characteristics.

For end users with sensitive processes, the voltage sag ride-through capability is usually the most important characteristic to consider. These loads can generally be impacted by very short duration events, and virtually all voltage sag conditions last at least 4 or 5 cycles (unless the fault is cleared by a current-limiting fuse).

Thus, one of the most common methods to quantify equipment susceptibility to voltage sags is using a magnitude-duration plot as shown in Fig. 3.6. It shows the voltage sag magnitude that will cause equipment to misoperate as a function of the sag duration.

Figure 3.6 Typical equipment voltage sag ride-through capability curves.

The curve labeled CBEMArepresents typical equipment sensitivity characteristics. The curve was developed by the CBEMA and was adopted in IEEE 446 (Orange Book). Since the association reorganized in 1994 and was subsequently renamed the Information Technology Industry Council (ITI), the CBEMA curve was also updated and renamed the ITI curve.

Typical loads will likely trip off when the voltage is below the CBEMA, or ITI, curve. The curve labeled ASD represents an example ASD voltage sag ride through capability for a device that is very sensitive to voltage sags. It trips for sags below 0.9 pu that last for only 4 cycles.

The contactor curve represents typical contactor sag ride-through characteristics. It trips for voltage sags below 0.5 pu that last for more than 1 cycle. The area of vulnerability for motor contactors shown in Fig. 3.5 indicates that faults within this area will cause the end-user voltage to drop below 0.5 pu.

  Figure 3.5 Illustration of an area of vulnerability.

Motor contactors having a minimum voltage sag ride-through capability of 0.5 pu would have tripped out when a fault causing a voltage sag with duration of more than 1 cycle occurs within the area of vulnerability. However, faults outside this area will not cause the voltage to drop below 0.5 pu.

The same discussion applies to the area of vulnerability for ASD loads. The less sensitive the equipment, the smaller the area of vulnerability will be (and the fewer times sags will cause the equipment to misoperate).


One means of ensuring that harmonic currents of nonlinear components will not unduly interact with the remaining part of the power system is to place filters near or close to nonlinear loads. The main function of a filter is either to bypass harmonic currents, block them from entering the power system, or compensate them by locally supplying harmonic currents.

Due to the lower impedance of the filter in comparison to the impedance of the system, harmonic currents will circulate between the load and the filter and do not affect the entire system; this is called series resonance. If other frequencies are to be controlled (e.g., that of arc furnaces), additional tuned filters are required.

Harmonic filters are broadly classified into passive, active, and hybrid structures. These filters can only compensate for harmonic currents and/or harmonic voltages at the installed bus and do not consider the power quality of other buses. New generations of active filters are active-power line conditioners that
are capable of minimizing the power quality of the entire system.

Passive filters are made of passive components (inductance, capacitance, and resistance) tuned to the harmonic frequencies that are to be attenuated. The values of inductors and capacitors are selected to provide low impedance paths at the selected frequencies. Passive filters are generally designed to remove one or two harmonics (e.g., the 5th and 7th).

They are relatively inexpensive compared with other means for eliminating harmonic distortion, but also suffer from some inherent limitations, including:

1. Interactions with the power system;

2. Forming parallel resonance circuits with system impedance (at fundamental and/or harmonic frequencies). This may result in a situation that is worse than the condition being corrected. It may also result in system or equipment failure;

3. Changing characteristics (e.g., their notch frequency) due to filter parameter variations;

4. Unsatisfactory performance under variations of nonlinear load parameters;

5. Compensating a limited number of harmonics;

6. Not considering the power quality of the entire system; and

7. Creating parallel resonance. This resonance frequency must not necessarily coincide with any significant system harmonic.

Passive filters are commonly tuned slightly lower than the attenuated harmonic to provide a margin of safety in case there are some changes in system parameters (due to temperature variations and/or failures). For this reason filters are added to the system starting with the lowest undesired harmonic.

For example, installing a seventh-harmonic filter usually requires that a fifth-harmonic filter also be installed. Designing passive filters is a relatively simple but tedious matter. For the proper tuning of passive filters, the following steps should be followed:
8. Model the power system (including nonlinear loads) to indicate the location of harmonic sources and the orders of the injected harmonics. A harmonic power (load) flow algorithm should be used; however, for most applications with a single dominating harmonic source, a simplified equivalent model and hand calculations are adequate;

9. Place the hypothetical harmonic filter(s) in the model and reexamine the system. Filter(s) should be properly tuned to dominant harmonic frequencies; and

10. If unacceptable results (e.g., parallel resonance within system) are obtained, change filter location(s) and modify parameter values until results are satisfactory.

In addition to power quality improvement, harmonic filters can be configured to provide power factor correction. For such cases, the filter is designed to carry resonance harmonic currents, as well as fundamental current.

Active filters rely on active power conditioning to compensate for undesirable harmonic currents. They actually replace the portion of the sine wave that is missing in the nonlinear load current by detecting the distorted current and using power electronic switching devices to inject harmonic currents with complimentary magnitudes, frequencies, and phase shifts into the power system.

Their main advantage over passive filters is their fine response to changing loads and harmonic variations. Active filters can be used in very difficult circumstances where passive filters cannot operate successfully because of parallel resonance within the system.

They can also take care of more than one harmonic at a time and improve or mitigate other power quality problems such as flicker. They are particularly useful for large, distorting nonlinear loads fed from relatively weak points of the power system where the system impedance is relatively large. Active filters are relatively expensive and not feasible for small facilities.


What Are The Uses Of Power Quality Meter and Analyzers?

A number of manufacturers make “power-quality meters” and “power quality analyzers,” which are instruments similar to oscilloscopes, but that have a number of functions particularly suited to making power-quality measurements.

In measuring power quality, we must be able to trigger on events that are not continuous (such as a voltage sag) or transient (like that caused by lightning strikes or utility faults). For instance, typical power quality meters/ analyzers and analyzers have the following functionalities:

■ Data logging—capturing waveforms in real-time for later display

■ The ability to trigger on power-quality events such as sags, swells, or transients

■ Calculation of power-quality metrics such as total harmonic distortion in real-time

■ Spectrum analysis

■ Inputs for high-voltage probes and high-current probes. Numerous factors should be considered when selecting a power quality measurement meter/analyzer, including:

■ The number of channels (for instance, single-phase or three-phase)

■ The input voltage range

■ The current measurement range

■ Isolation

■ Communication capabilities (For example, can the instrument be networked or tied to a stand-alone computer?)

The power-quality analyzer A/D converts system voltages and currents. Power indices such as THD, harmonic content, and the like are calculated in real-time. In addition, the analyzer has on-board memory so data may be saved for future analysis.

In the output of a typical power-quality analyzer we see the time waveform of the line current in a copy machine and the harmonics.


A List Of Techniques To Improve Power Quality

Nonlinear loads produce harmonic currents that can propagate to other locations in the power system and eventually return back to the source. Therefore, harmonic current propagation produces harmonic voltages throughout the power systems.

Many mitigation techniques have been proposed and implemented to maintain the harmonic voltages and currents within recommended levels:

1. high power quality equipment design,
2. harmonic cancellation,
3. dedicated line or transformer,
4. optimal placement and sizing of capacitor banks,
5. derating of power system devices, and
6. harmonic filters (passive, active, hybrid) and custom power devices such as active power line conditioners (APLCs) and unified or universal power quality conditioners (UPQCs).

The practice is that if at PCC harmonic currents are not within the permissible limits, the consumer with the nonlinear load must take some measures to comply with standards.

However, if harmonic voltages are above recommended levels- and the harmonic currents injected comply with standards - the utility will have to take appropriate actions to improve the power quality.


It was shown before, the drop in voltage during a sag is due to a short circuit being present in the system. The moment the short circuit fault is cleared by the protection, the voltage starts to return to its original value.

The duration of a sag is thus determined by the fault-clearing time. However, the actual duration of a sag is normally longer than the fault-clearing time. Measurement of sag duration is less trivial than it might appear.

From a recording the sag duration may be obvious, but to come up with an automatic way for a power quality monitor to obtain the sag duration is no longer straightforward. The commonly used definition of sag duration is the number of cycles during which the rms voltage is below a given threshold.

This threshold will be somewhat different for each monitor but typical values are around 90% of the nominal voltage. A power quality monitor will typically calculate the rms value once every cycle.

The main problem is that the so-called post-fault sag will affect the sag duration. When the fault is cleared, the voltage does not recover immediately. This is mainly due to the reenergizing and reacceleration of induction motor load (Bollen, 1995).

This post-fault sag can last several seconds, much longer than the actual sag. Therefore, the sag duration as defined before, is no longer equal to the fault clearing time.

More seriously, different power quality monitors will give different values for the sag duration. As the rms voltage recovers slowly, a small difference in threshold setting may already lead to a serious difference in recorded sag duration (Bollen, 1999).

Generally speaking, faults in transmission systems are cleared faster than faults in distribution systems. In transmission systems, the critical fault-clearing time is rather small.

Thus, fast protection and fast circuit breakers are essential. Also, transmission and subtransmission systems are normally operated as a grid, requiring distance protection or differential protection, both of which allow for fast clearing of the fault.

The principal form of protection in distribution systems is overcurrent protection. This requires a certain amount of time-grading, which increases the fault-clearing time. An exception is formed by systems in which current-limiting fuses are used.

These have the ability to clear a fault within one half-cycle. In overhead distribution systems, the instantaneous trip of the recloser will lead to a short sag duration, but the clearing of a permanent fault will give a sag of much longer duration.

The so-called magnitude-duration plot is a common tool used to show the quality of supply at a certain location or the average quality of supply of a number of locations. Voltage sags due to faults can be shown in such a plot, as well as sags due to motor starting, and even long and short interruptions.


To quantify sag magnitude in radial systems, the voltage divider model, shown in Fig. 31.4, can be used, where ZS is the source impedance at the point of- common coupling; and ZF is the impedance between the point-of-common coupling and the fault.

  The point-of-common coupling (pcc) is the point from which both the fault and the load are fed. In other words, it is the place where the load current branches off from the fault current.

In the voltage divider model, the load current before, as well as during the fault is neglected. The voltage at the pcc is found from:

Vsag = ZF / (ZS + ZF)

where it is assumed that the pre-event voltage is exactly 1 pu, thus E = 1. The same expression can be derived for constant-impedance load, where E is the pre-event voltage at the pcc. We see from the Eq. that the sag becomes deeper for faults electrically closer to the customer (when ZF becomes smaller), and for weaker systems (when ZS becomes larger).

Equation can be used to calculate the sag magnitude as a function of the distance to the fault. Therefore, we write ZF = zd, with z the impedance of the feeder per unit length and d the distance between the fault and the pcc, leading to:

Vsag = zd / (ZS + zd)

This expression has been used to calculate the sag magnitude as a function of the distance to the fault for a typical 11 kV overhead line. For the calculations, a 150-mm2 overhead line was used and fault levels of 750 MVA, 200 MVA, and 75 MVA.

The fault level is used to calculate the source impedance at the pcc and the feeder impedance is used to calculate the impedance between the pcc and the fault. It is assumed that the source impedance is purely reactive, thus ZS = j 0.161 V for the 750 MVA source. The impedance of the 150 mm2 overhead
line is z = 0.117 + j 0.315 V/km.


Consider the distribution network shown in Fig. 31.3, where the numbers (1 through 5) indicate fault positions and the letters (A through D) loads. A fault in the transmission network, fault position 1, will cause a serious sag for both substations bordering the faulted line.

This sag is transferred down to all customers fed from these two substations. As there is normally no generation connected at lower voltage levels, there is nothing to keep up the voltage.

The result is that all customers (A, B, C, and D) experience a deep sag. The sag experienced by A is likely to be somewhat less deep, as the generators connected to that substation will keep up the voltage.

A fault at position 2 will not cause much voltage drop for customer A. The impedance of the transformers between the transmission and the subtransmission system are large enough to considerably limit the voltage drop at high-voltage side of the transformer.

The sag experienced by customer A is further mitigated by the generators feeding into its local transmission substation. The fault at position 2 will, however, cause a deep sag at both subtransmission substations and thus for all customers fed from here (B, C, and D).

A fault at position 3 will cause a short or long interruption for customer D when the protection clears the fault. Customer C will only experience a deep sag. Customer B will experience a shallow sag due to the fault at position 3, again due to the transformer impedance.

Customer A will probably not notice anything from this fault. Fault 4 causes a deep sag for customer C and a shallow one for customer D. For fault 5, the result is the other way around: a deep sag for customer D and a shallow one for customer C.

Customers A and B will not experience any significant drop in voltage due to faults 4 and 5.

FIGURE 31.3 Distribution network with load positions (A through D) and fault positions (1 through 5).


Waveform distortion is defined as a steady-state deviation from an ideal sine wave of power frequency principally characterized by the spectral content of the deviation.

There are five primary types of waveform distortion:
■ DC offset
■ Harmonics
■ Interharmonics
■ Notching
■ Noise

DC offset. The presence of a dc voltage or current in an ac power system is termed dc offset. This can occur as the result of a geomagnetic disturbance or asymmetry of electronic power converters. Incandescent light bulb life extenders, for example, may consist of diodes that reduce the rms voltage supplied to the light bulb by half-wave rectification.

Direct current in ac networks can have a detrimental effect by biasing transformer cores so they saturate in normal operation. This causes additional heating and loss of transformer life. Direct current may also cause the electrolytic erosion of grounding electrodes and other connectors.

Harmonics. Harmonics are sinusoidal voltages or currents having frequencies that are integer multiples of the frequency at which the supply system is designed to operate (termed the fundamental frequency; usually 50 or 60 Hz). Periodically distorted waveforms can be decomposed into a sum of the fundamental frequency and the harmonics.

Harmonic distortion originates in the nonlinear characteristics of devices and loads on the power system. Harmonic distortion levels are described by the complete harmonic spectrum with magnitudes and phase angles of each individual harmonic component. It is also common to use a single quantity, the total harmonic distortion (THD), as a measure of the effective value of harmonic distortion.

Current distortion levels can be characterized by a THD value, as previously described, but this can often be misleading. For example, many adjustable-speed drives will exhibit high THD values for the input current when they are operating at very light loads. This is not necessarily a significant concern because the magnitude of harmonic current is low, even though its relative distortion is high.

To handle this concern for characterizing harmonic currents in a consistent fashion, IEEE Standard 519-1992 defines another term, the total demand distortion (TDD). This term is the same as the total harmonic distortion except that the distortion is expressed as a percent of some rated load current rather than as a percent of the fundamental current magnitude at the instant of measurement. IEEE Standard 519-1992 provides guidelines for harmonic current and voltage distortionlevels on distribution and transmission circuits.

Interharmonics. Voltages or currents having frequency components that are not integer multiples of the frequency at which the supply system is designed to operate (e.g., 50 or 60 Hz) are called interharmonics. They can appear as discrete frequencies or as a wideband spectrum. Interharmonics can be found in networks of all voltage classes.

The main sources of interharmonic waveform distortion are static frequency converters, cycloconverters, induction furnaces, and arcing devices. Power line carrier signals can also be considered as interharmonics. There is now a better understanding of the origins and effects of interharmonic distortion.

It is generally the result of frequency conversion and is often not constant; it varies with load. Such interharmonic currents can excite quite severe resonances on the power system as the varying interharmonic frequency becomes coincident with natural frequencies of the system. They have been shown to affect power-line-carrier signaling and induce visual flicker in fluorescent and other arc lighting as well as in computer display devices.

Notching. Notching is a periodic voltage disturbance caused by the normal operation of power electronic devices when current is commutated from one phase to another. Since notching occurs continuously, it can be characterized through the harmonic spectrum of the affected voltage.

However, it is generally treated as a special case. The frequency components associated with notching can be quite high and may not be readily characterized with measurement equipment normally used for harmonic analysis.

Noise. Noise is defined as unwanted electrical signals with broadband spectral content lower than 200 kHz superimposed upon the power system voltage or current in phase conductors, or found on neutral conductors or signal lines.

Noise in power systems can be caused by power electronic devices, control circuits, arcing equipment, loads with solid-state rectifiers, and switching power supplies. Noise problems are often exacerbated by improper grounding that fails to conduct noise away from the power system.

Basically, noise consists of any unwanted distortion of the power signal that cannot be classified as harmonic distortion or transients. Noise disturbs electronic devices such as microcomputer and programmable controllers. The problem can be mitigated by using filters, isolation transformers, and line conditioners.


The magnitude of a voltage sag is determined from the rms voltage. The rms voltage for the sag in Fig. 31.1 is shown in Fig. 31.2. The rms voltage has been calculated over a one-cycle sliding window:

with N the number of samples per cycle, and v(i) the sampled voltage in time domain. The rms voltage as shown in Fig. 31.2 does not immediately drop to a lower value, but takes one cycle for the transition.

FIGURE 31.2 One-cycle rms voltage for the voltage sag

This is due to the finite length of the window used to calculate the rms value. We also see that the rms value during the sag is not completely constant and that the voltage does not immediately recover after the fault.

There are various ways of obtaining the sag magnitude from the rms voltages. Most power quality monitors take the lowest value obtained during the event. As sags normally have a constant rms value during the deep part of the sag, using the lowest value is an acceptable approximation.

The sag is characterized through the remaining voltage during the event. This is then given as a percentage of the nominal voltage. Thus, a 70% sag in a 230-V system means that the voltage dropped to 161 V.

The confusion with this terminology is clear. One could be tricked into thinking that a 70% sag refers to a drop of 70%, thus a remaining voltage of 30%. The recommendation is therefore to use the phrase ‘‘a sag down to 70%.’’

Characterizing the sag through the actual drop in rms voltage can solve this ambiguity, but this will introduce new ambiguities like the choice of the reference voltage.


Voltage sags are short duration reductions in rms voltage, mainly caused by short circuits and starting of large motors. The interest in voltage sags is due to the problems they cause on several types of equipment.

Adjustable-speed drives, process-control equipment, and computers are especially notorious for their sensitivity (Conrad et al., 1991; McGranaghan et al., 1993). Some pieces of equipment trip when the rms voltage drops below 90% for longer than one or two cycles.

Such a piece of equipment will trip tens of times a year. If this is the process-control equipment of a paper mill, one can imagine that the costs due to voltage sags can be enormous.

A voltage sag is not as damaging to industry as a (long or short) interruption, but as there are far more voltage sags than interruptions, the total damage due to sags is still larger. Another important aspect of voltage sags is that they are hard to mitigate.

Short interruptions and many long interruptions can be prevented via simple, although expensive measures in the local distribution network. Voltage sags at equipment terminals can be due to short-circuit faults hundreds of kilometers away in the transmission system. It will be clear that there is no simple method to prevent them.

An example of a voltage sag is shown in Fig. 31.1.1 The voltage amplitude drops to a value of about 20% of its pre-event value for about two and a half cycles, after which the voltage recovers again.

  FIGURE 31.1 A voltage sag—voltage in one phase in time domain.

The event shown in Fig. 31.1 can be characterized as a voltage sag down to 20% (of the pre-event voltage) for 2.5 cycles (of the fundamental frequency). This event can be characterized as a voltage sag with a magnitude of 20% and a duration of 2.5 cycles.


Power system harmonics are not a new topic, but the proliferation of high-power electronics used in motor drives and power controllers has necessitated increased research and development in many areas relating to harmonics.

For many years, high-voltage direct current (HVDC) stations have been a major focus area for the study of power system harmonics due to their rectifier and inverter stations. Roughly two decades ago, electronic devices that could handle several kW up to several MW became commercially viable and reliable products.

This technological advance in electronics led to the widespread use of numerous converter topologies, all of which represent nonlinear elements in the power system.

Even though the power semiconductor converter is largely responsible for the large-scale interest in power system harmonics, other types of equipment also present a nonlinear characteristic to the power system. In broad terms, loads that produce harmonics can be grouped into three main categories covering (1) arcing loads, (2) semiconductor converter loads, and (3) loads with magnetic saturation of iron cores.

Arcing loads, like electric arc furnaces and florescent lamps, tend to produce harmonics across a wide range of frequencies with a generally decreasing relationship with frequency. Semiconductor loads, such as adjustable-speed motor drives, tend to produce certain harmonic patterns with relatively predictable amplitudes at known harmonics.

Saturated magnetic elements, like overexcited transformers, also tend to produce certain ‘‘characteristic’’ harmonics. Like arcing loads, both semiconductor converters and saturated magnetics produce harmonics that generally decrease with frequency.

Regardless of the load category, the same fundamental theory can be used to study power quality problems associated with harmonics. In most cases, any periodic distorted power system waveform (voltage, current, flux, etc.) can be represented as a series consisting of a DC term and an infinite sum of sinusoidal terms.

A vast amount of theoretical mathematics has been devoted to the evaluation of the terms in the infinite sum, but It is reasonable to presume that instrumentation is available that will provide both the magnitude Fi and the phase angle ui for each term in the series. Taken together, the magnitude and phase of the ith term completely describe the ith harmonic.

It should be noted that not all loads produce harmonics that are integer multiples of the power frequency. These noninteger multiple harmonics are generally referred to as interharmonics and are commonly produced by arcing loads and cycloconverters.

All harmonic terms, both integer and noninteger multiples of the power frequency, are analytically treated in the same manner, usually based on the principle of superposition.


There are three basic reasons for grounding a power system: personal safety, protective device operation, and noise control. All three of these reasons will be addressed.

Personal Safety
The most important reason for grounding a device on a power system is personal safety. The safety ground, as it is sometimes called, is provided to reduce or eliminate the chance of a high touch potential if a fault occurs in a piece of electrical equipment.

Touch potential is defined as the voltage potential between any two conducting materials that can be touched simultaneously by an individual or animal. Figure 29.2 illustrates a dangerous touch potential situation.  

The ‘‘hot’’ conductor in the piece of equipment has come in contact with the case of the equipment. Under normal conditions, with the safety ground intact, the protective device would operate when this condition occurred.

However, in Fig. 29.2, the safety ground is missing. This allows the case of the equipment to float above ground since the case of the equipment is not grounded through its base. In other words, the voltage potential between the equipment case and ground is the same as the voltage potential between the hot leg and ground. If the operator would come in contact with the case and ground (the floor), serious injury could result.

In recent years, manufacturers of hand held equipment, drills, saws, hair dryers, etc. have developed double insulated equipment. This equipment generally does not have a safety ground. However, there is never any conducting material for the operator to contact and therefore there is no touch potential hazard. If the equipment becomes faulted, the case or housing of the equipment is not energized.

Protective Device Operation
As mentioned in the previous section, there must be a path for fault current to return to the source if protective devices are to operate during fault conditions. The National Electric Code (NEC) requires that an effective grounding path must be mechanically and electrically continuous (NEC 250–51), have the capacity to carry any fault currents imposed on it without damage (NEC 250–75).

The NEC also states that the ground path must have sufficiently low impedance to limit the voltage and facilitate protective device operation. Finally, the earth cannot serve as the equipment-grounding path (NEC-250–91(c)).

The formula to determine the maximum circuit impedance for the grounding path is:
Ground Path Impedance = Maximum Voltage to Ground (Overcurrent Protection Rating x 5)

Noise Control
Noise control is the third main reason for grounding. Noise is defined as unwanted voltages and currents on a grounding system. This includes signals from all sources whether it is radiated or conducted.

As stated, the primary reason for grounding is safety and is regulated by the NEC and local codes. Any changes to the grounding system to improve performance or eliminate noise control must be in addition to the minimum NEC requirements.

When potential differences occur between different grounding systems, insulation can be stressed and circulating currents can be created in low voltage cables (e.g., communications cables). In today’s electrical environment, buildings that are separated by large physical distances are typically tied together via a communication circuit.

An example of this would be a college campus that may cover several square miles. Each building has its own grounding system. If these grounding systems are not tied together, a potential difference on the grounding circuit for the communication cable can occur.

The idea behind grounding for noise control is to create an equipotential grounding system, which in turn limits or even eliminates the potential differences between the grounding systems. If the there is an equipotential grounding system and currents are injected into the ground system, the potential of the whole grounding system will rise and fall and potential differences will not occur.

Supplemental conductors, ground reference grids, and ground plates can all be used to improve the performance of the system as it relates to power quality. Optically isolated communications can also improve the performance of the system.

By using the opto-isolators, connecting the communications to different ground planes is avoided. All improvements to the grounding system must be done in addition to the requirements for safety.


What Are Super Conductors?

The ideal superconducting state is characterized by two fundamental properties, which are the disappearance of resistance when the temperature is reduced to a critical value, and the expulsion of any magnetic flux in the material when the critical temperature (Tc) is reached.

Superconductivity was first discovered in the element mercury, in 1911. Other elements have subsequently been found to exhibit superconductivity and theories have been developed to explain the phenomenon. The critical temperatures for these materials were typically about 10 K (−263°C), which meant that they had to be cooled with liquid helium at 4 K.

In general these materials have been of academic interest only because they could only support a low current density in a low magnetic field without losing their superconducting properties. In the 1950s a new class of materials was discovered. These are the metallic alloys, the most important among them being niobium titanium and niobium tin.

The highest critical temperature achieved by these materials is 23.2 K and they can be used to produce magnetic flux densities of over 15 T. The main commercial application for these low-Tc superconductors is for magnets in medical imaging equipment which require the high fields to excite magnetic resonance in nuclei of hydrogen and other elements.

The magnet or solenoid of the magnetic resonance imaging (MRI) unit has an internal diameter of about 1.2 m and the patient to be examined is put into this aperture. The image from the resonance test shows unexpected concentrations of fluids or tissue and enables a diagnosis.

Superconducting magnets producing high magnetic fields are also used in magnetic research and in high energy physics research; other applications such as dc motors and generators, levitated trains, cables and ac switches have been explored but the complexity and high cost of providing the liquid helium environment prevented commercial development in most cases.

In late 1986 a ceramic material LaBaCuO was discovered to be superconducting at 35 K and in 1987 the material YBaCuO was found to have a critical temperature of 92 K. Since that time the critical temperatures of these new high temperature superconducting (HTS) materials has progressively increased to over 130 K.

Examples of these are BiSrCaCuO (with a Tc of 106 K), ThBaCaCuO (Tc of 125 K) and HgBaCaCuO (Tc of 133 K). The enormous significance of these discoveries is that these materials will be superconducting in liquid nitrogen, which has a boiling point of 77 K and is much easier and cheaper to provide than helium.

Much work has been directed towards finding materials with higher Tc values but this has remained at 133 K for some time. However, considerable effort with resulting success has been directed to the production of suitable HTS conductors. The HTS material is very brittle and it is deposited using laser deposition onto a suitable substrate tape.

The tape is 3 mm wide and cables of up to 600 m in length have been produced. There are many trials being made of the application of the HTS cables throughout the world including USA, Europe and Japan. There are prototypes of power transformers, underground power cables, large motors and generators, and fault current limiters in active development and in use.

The electricity supply of the City of Geneva in Switzerland is completely provided by power transformers wound with HTS conductors. Detroit is being re-equipped with HTS power cable for its transmission system and copper cables weighing over 7 tons are being replaced with HTS cables of less than 0.12 tons. These and other developments will help to establish the long-term feasibility of the HTS material. It is expected that there will be definite power saving from the use of HTS.

Small-scale applications which use HTS material include SQUIDS (Superconducting Quantum Interference Devices) which measure very low magnetic fields. They are applied in measurements in biomagnetism (investigations of electrical activity in the heart, brain and muscles) and in geophysics for the study of rock magnetism and anomalies in the earth’s surface.


Thermal generating plants are designed and constructed to convert energy from fuel (coal, oil, gas, or radiation) into electric power. The actual conversion is accomplished by a turbine-driven generator.

Thermal generating plants differ from industrial plants in that the nature of the product never changes. The plant will always produce electric energy. The things that may change are the fuel used (coal, oil, or gas) and environmental requirements.

Many plants that were originally designed for coal were later converted to oil, converted back to coal, and then converted to gas. Environmental requirements have changed, which has required the construction of air and water emissions control systems.

Plant electrical systems should be designed to allow for further growth. Sizing of transformers and buses is at best a matter of guesswork. The plant electrical system should be sized at 5 to 10% the size of the generating unit depending on the plant configuration and number of units at the plant site.

Plant Auxiliary System
Selection of Auxiliary System Voltages
The most common plant auxiliary system voltages are 13,800 V, 6900 V, 4160 V, 2400 V, and 480 V. The highest voltage is determined by the largest motor. If motors of 4000 hp or larger are required, one should consider using 13,800 V. If the largest motor required is less than 4000 hp, then 4160 V should be satisfactory.

Auxiliary System Loads
Auxiliary load consists of motors and transformers. Transformers supply lower level buses which supply smaller motors and transformers which supply lower voltage buses. Generation plants built before 1950 may have an auxiliary generator that is connected to the main generator shaft. The auxiliary generator will supply plant loads when the plant is up and running.

Auxiliary System Power Sources
The power sources for a generating plant consist of one or more off-site sources and one or more onsite sources. The on-site sources are the generator and, in some cases, a black start diesel generator or a gas turbine generator which may be used as a peaker.

Auxiliary System Voltage Regulation Requirements
Most plants will not require voltage regulation. A load flow study will indicate if voltage regulation is required. Transformers with tap changers, static var compensators, or induction regulators may be used to keep plant bus voltages within acceptable limits. Switched capacitor banks and overexcited synchronous motors may also be used to regulate bus voltage.

Plant One-Line Diagram
The one-line diagram is the most important document you will use. Start with a conceptual one-line and add detail as it becomes available. The one-line diagram will help you think about your design and make it easier to discuss with others.

Do not be afraid to get something on paper very early and modify as you get more information about the design. Consider how the plant will be operated. Will there be a start-up source and a running source? Are there on-site power sources?
Plant Equipment Voltage Ratings
Establish at least one bus for each voltage rating in the plant. Two or more buses may be required depending on how the plant will be operated.

Grounded vs. Ungrounded Systems
A method of grounding must be determined for each voltage level in the plant.

Most systems will be grounded in some manner with the exception for special cases of 120-V control systems which may be operated ungrounded for reliability reasons. An ungrounded system may be allowed to continue to operate with a single ground on the system. Ungrounded systems are undesirable because ground faults are difficult to locate. Also, ground faults can result in system overvoltage, which can damage equipment that is connected to the ungrounded system.

Most systems 480 V and lower will be solidly grounded.

Low-Resistance Grounding
Low-resistance grounding systems are used at 2400 V and above. This system provides enough ground fault current to allow relay coordination and limits ground fault current to a value low enough to prevent equipment damage.

High-Resistance Grounding
High-resistance grounding systems limit ground fault current to a very low value but make relay coordination for ground faults difficult.


Hydroelectric power generation involves the storage of a hydraulic fluid, normally water, conversion of the hydraulic energy of the fluid into mechanical energy in a hydraulic turbine, and conversion of the mechanical energy to electrical energy in an electric generator.

The first hydroelectric power plants came into service in the 1880s and now comprise approximately 22% (660 GW) of the world’s installed generation capacity of 3000 GW (Electric Power Research Institute, 1999).

Hydroelectricity is an important source of renewable energy and provides significant flexibility in base loading, peaking, and energy storage applications.

While initial capital costs are high, the inherent simplicity of hydroelectric plants, coupled with their low operating and maintenance costs, long service life, and high reliability, make them a very cost effective and flexible source of electricity generation.

Especially valuable is their operating characteristic of fast response for start-up, loading, unloading, and following of system load variations. Other useful features include their ability to start without the availability of power system voltage (“black start capability”), ability to transfer rapidly from generation mode to synchronous condenser mode, and pumped storage application.

Hydroelectric units have been installed in capacities ranging from a few kilowatts to nearly 1 GW. Multi-unit plant sizes range from a few kilowatts to a maximum of 18 GW.

Planning of Hydroelectric Facilities

Hydroelectric plants are located in geographic areas where they will make economic use of hydraulic energy sources. Hydraulic energy is available wherever there is a flow of liquid and head. Head represents potential energy and is the vertical distance through which the fluid falls in the energy conversion process.

The majority of sites utilize the head developed by fresh water; however, other liquids such as salt water and treated sewage have been utilized. The siting of a prospective hydroelectric plant requires careful evaluation of technical, economic, environmental, and social factors.

A significant portion of the project cost may be required for mitigation of environmental effects on fish and wildlife and re location of infrastructure and population from flood plains.

Hydroelectric Plant Schemes
There are three main types of hydroelectric plant arrangements, classified according to the method of controlling the hydraulic flow at the site:

1. Run-of-the-river plants, having small amounts of water storage and thus little control of the flow through the plant.
2. Storage plants, having the ability to store water and thus control the flow through the plant on a daily or seasonal basis.

3. Pumped storage plants, in which the direction of rotation of the turbines is reversed during offpeak hours, pumping water from a lower reservoir to an upper reservoir, thus “storing energy” for later production of electricity during peak hours.


The wind is a free, clean, and inexhaustible energy source. It has served humankind well for many centuries by propelling ships and driving wind turbines to grind grain and pump water. Denmark was the first country to use wind for generation of electricity.

The Danes were using a 23-m diameter wind turbine in 1890 to generate electricity. By 1910, several hundred units with capacities of 5 to 25 kW were in operation in Denmark (Johnson, 1985). By about 1925, commercial wind-electric plants using two and three-bladed propellers appeared on the American market.

The most common brands were Wincharger (200 to 1200 W) and Jacobs (1.5 to 3 kW). These were used on farms to charge storage batteries which were then used to operate radios, lights, and small appliances with voltage ratings of 12, 32, or 110 volts.

A good selection of 32-VDC appliances was developed by the industry to meet this demand. In addition to home wind-electric generation, a number of utilities around the world have built larger wind turbines to supply power to their customers. The largest wind turbine built before the late 1970s was a 1250-kW machine built on Grandpa’s Knob, near Rutland, Vermont, in 1941.

This turbine, called the Smith-Putnam machine, had a tower that was 34 m high and a rotor 53 m in diameter. The rotor turned an ac synchronous generator that produced 1250 kW of electrical power at wind speeds above 13 m/s.

After World War II, we entered the era of cheap oil imported from the Middle East. Interest in wind energy died and companies making small turbines folded. The oil embargo of 1973 served as a wakeup call, and oil-importing nations around the world started looking at wind again. The two most important countries in wind power development since then have been the U.S. and Denmark (Brower et al., 1993).

The U.S. immediately started to develop utility-scale turbines. It was understood that large turbines had the potential for producing cheaper electricity than smaller turbines, so that was a reasonable decision. The strategy of getting large turbines in place was poorly chosen, however. The Department of Energy decided that only large aerospace companies had the manufacturing and engineering capability to build utility-scale turbines.

This meant that small companies with good ideas would not have the revenue stream necessary for survival. The problem with the aerospace firms was that they had no desire to manufacture utility-scale wind turbines.

They gladly took the government’s money to build test turbines, but when the money ran out, they were looking for other research projects. The government funded a number of test turbines, from the 100 kW MOD-0 to the 2500 kW MOD-2. These ran for brief periods of time, a few years at most. Once it was obvious that a particular design would never be cost competitive, the turbine was quickly salvaged.

Denmark, on the other hand, established a plan whereby a landowner could buy a turbine and sell the electricity to the local utility at a price where there was at least some hope of making money. The early turbines were larger than what a farmer would need for himself, but not what we would consider utility scale.

This provided a revenue stream for small companies. They could try new ideas and learn from their mistakes. Many people jumped into this new market. In 1986, there were 25 wind turbine manufacturers in Denmark. The Danish market gave them a base from which they could also sell to other countries.

It was said that Denmark led the world in exports of two products: wind turbines and butter cookies There has been consolidation in the Danish industry since 1986, but some of the companies have grown large. Vestas, for example, has more installed wind turbine capacity worldwide than any other manufacturer.

Prices have dropped substantially since 1973, as performance has improved. It is now commonplace for wind power plants (collections of utility-scale turbines) to be able to sell electricity for under four cents per kilowatt hour. Total installed worldwide capacity at the start of 1999 was almost 10,000 MW, according to the trade magazine Wind Power Monthly (1999).