THREE PHASE VOLTAGE

The relationship between magnetism and electrical current was discovered and documented by Oerstad in 1819. He found that if an electric current was caused to flow through a conductor that a magnetic field was produced around that conductor. In 1831, Michael Faraday discovered that if a conductor is moved through a magnetic field, an electrical voltage is induced in the conductor. The magnitude of this generated voltage is directly proportional to the strength of the magnetic field and the rate at which the conductor crosses the magnetic field. The induced voltage has a polarity that will oppose the change causing the induction – Lenz’s law. This natural phenomenon is known as Generator Action and is described today by Faraday’s Law of
Electro Magnetic Induction: (Vind = ∆Ø/∆t), where Vind = induced voltage, ∆Ø = change in flux density, ∆t = change in time All rotary generators built today use the basic principles of Generator Action.

THREE PHASE VOLTAGE

Three phase voltage is developed using the same principles as the development of single phase voltage. Three (3) coils are required positioned 120 electrical degrees apart. A rotating magnetic field induces voltage in the coils which when aggregated produce the familiar three phase voltage pattern.

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TYPES OF GENERATORS

Essentially, there are two basic types of generators:
• DC generators
• AC generators: Asynchronous (Induction) generators and Synchronous generators

INDUCTION GENERATORS

The induction generator is nothing more than an induction motor driven above its synchronous speed by an amount not exceeding the full load slip the unit would have as a motor. Assuming a full load slip of 3%, a motor with a synchronous speed of 1200 rpm would have a full load speed of 1164 rpm. This unit could also be driven by an external prime mover at 1236 rpm for use as an induction generator.

The induction generator requires one additional item before it can produce power – it requires a source of leading VAR’s for excitation. The VAR’s may be supplied by capacitors (this requires complex control) or from the utility grid. Induction generators are inexpensive and simple machines, however, they offer little control over their output. The induction generator requires no separate DC excitation, regulator controls, frequency control or governor.

SYNCHRONOUS GENERATORS

Synchronous generators are used because they offer precise control of voltage, frequency, VARs and WATTs. This control is achieved through the use of voltage
regulators and governors. A synchronous machine consists of a stationary armature winding (stator) with many wires connected in series or parallel to obtain the desired terminal voltage.

The armature winding is placed into a slotted laminated steel core. A synchronous machine also consists of a revolving DC field - the rotor. A mutual flux developed across the air gap between the rotor and stator causes the interaction necessary to produce an EMF. As the magnetic flux developed by the DC field poles crosses the air gap of the stator windings, a sinusoidal voltage is developed at the generator output terminals. This process is called electromagnetic induction.

The magnitude of the AC voltage generated is controlled by the amount of DC exciting current supplied to the field. if “FIXED” excitation were applied, the voltage magnitude would be controlled by the speed of the rotor (E=4.44fnBA), however, thismwould necessitate a changing frequency! Since the frequency component of the power system is to be held constant, solid state voltage regulators or static exciters are commonly used to control the field current and thereby accurately control generator terminal voltage.

The frequency of the voltage developed by the generator depends on the speed of the rotor and the number of field poles. For a 60 Hz system, Frequency = speed(rpm)*pole pairs/60.

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History Of Electric Power

Benjamin Franklin is known for his discovery of electricity. Born in 1706, he began studying electricity in the early 1750s. His observations, including his kite experiment, verified the nature of electricity. He knew that lightning was very powerful and dangerous. The famous 1752 kite experiment featured a pointed metal piece on the top of the kite and a metal key at the base end of the kite string. The string went through the key and attached to a Leyden jar. (A Leyden jar consists of two metal conductors separated by an insulator.) He held the string with a short section of dry silk as insulation from the lightning energy. He then flew the kite in a thunderstorm. He first noticed that some loose strands of the hemp string stood erect, avoiding one another. (Hemp is a perennial American plant used in rope making by the Indians.) He proceeded to touch the key with his knuckle and received a small electrical shock.

Between 1750 and 1850 there were many great discoveries in the principles of electricity and magnetism by Volta, Coulomb, Gauss, Henry, Faraday, and others. It was found that electric current produces a magnetic field and that a moving magnetic field produces electricity in a wire. This led to many inventions such as the battery (1800), generator (1831), electric motor (1831), telegraph (1837), and telephone (1876), plus many other intriguing inventions.

In 1879, Thomas Edison invented a more efficient lightbulb, similar to those in use today. In 1882, he placed into operation the historic Pearl Street steam–electric plant and the first direct current (dc) distribution system in New York City, powering over 10,000 electric lightbulbs. By the late 1880s, power demand for electric motors required 24-hour service and dramatically raised electricity demand for transportation and other industry needs. By the end of the 1880s, small, centralized areas of electrical power distribution were sprinkled across U.S. cities. Each distribution center was limited to a service range of a few blocks because of the inefficiencies of transmitting direct current. Voltage could not be increased or decreased using direct current systems, and a way to to transport power longer distances was needed.

To solve the problem of transporting electrical power over long distances, George Westinghouse developed a device called the “transformer.” The transformer allowed electrical energy to be transported over long distances efficiently. This made it possible to supply electric power to homes and businesses located far from the electric generating plants. The application of transformers required the distribution system to be of the alternating current (ac) type as opposed to direct current (dc) type.

The development of the Niagara Falls hydroelectric power plant in 1896 initiated the practice of placing electric power generating plants far from consumption areas. The Niagara plant provided electricity to Buffalo, New York, more than 20 miles away. With the Niagara plant, Westinghouse convincingly demonstrated the superiority of transporting electric power over long distances using alternating current (ac). Niagara was the first large power system to supply multiple large consumers with only one power line.

Since the early 1900s alternating current power systems began appearing throughout the United States. These power systems became interconnected to form what we know today as the three major power grids in the United States and Canada. The remainder of this chapter discusses the fundamental terms used in today’s electric power systems based on this history.

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How to select the correct motor starting method - Overview

The selection of a suitable starting method for a motor/load combination is becoming increasingly important as additional loads are added to existing utility and distribution systems. In the past, ample capacities were available in the utility networks to support the needs of industry. As well, the distribution systems of most North American industries were established during the industrial and technological boom years preceding the Second World War. In the 1990’s, the viability for the construction of new electrical generation plants became prohibitive. With lower North American utility generating capacity and increased risks involved in the de-regulation of this utility, stability and voltage drop concerns have become very real issues that face all electrical power consumers.

Problem
Full voltage starting of motors can produce objectionable voltage flicker, mechanical stress to gear boxes or belt drive systems and create pressure surges or water hammer in pumping applications. Starting a motor at reduced voltage can help reduce or overcome these problems. If the load cannot be accelerated to full speed using full voltage and current, it cannot be accelerated to full speed using reduced voltage and current.

Application Solution
There are several factors to be considered when selecting the starting equipment for any electric motor driven load. These include, but are not limited to:
1. The source of power and the effects the motor starting currents will have on the source and the stability of the system voltage
2. The starting and breakdown torque characteristics of the motor (motor speed torque characteristics)
3. The motor starting characteristics (torque) that correspond to the motor best suited to the load
characteristics at full load and speed
4. The starting characteristics of: motor torque load torque, accelerating load torque (load inertia) the motor starting, accelerating and running torque on the driven load
5. The available short circuit capacity of the distribution system
6. The operating speed range of the connected load.
7. Process considerations: shock, vibration, mechanical hammer, the control and maintenance of different starting methods.

The initial inrush currents, locked rotor currents and the resulting torque values produced, are the factors that determine whether the motor can be applied directly across the line, or whether the current has to be reduced to get the required performance to match the load requirements and/or utility line voltage flicker or voltage dip specifications.

Full voltage starting can be used whenever the driven load can withstand the shock of instantaneously applying full voltage to the motor and where line disturbances can be tolerated. Full voltage starting uses a main contactor to apply the motor stator windings directly across the main system voltage. This type of starting method provides the lowest cost, a basic and simple design of controller, resulting in low maintenance and the highest starting torque.

Reduced voltage starting may be required if full voltage starting creates objectionable line disturbances on the distribution system or where reduction of mechanical stress to gear boxes or belt drive systems is required. It must be noted that when the starting torque will decrease proportional to the percent squared of voltage applied (i.e. 50% voltage produces 25% torque =0.50 squared). This phenomenon also occurs in the opposite manner when the voltage is increased.
There are three main reasons to apply reduced voltage to medium voltage motors:
1. To reduce the mechanical effect of across the starting and stopping
2. To limit the inrush current inherent with full voltage starting
3. To reduce the effects of pressure surges and water hammer in pumping systems.

Mechanical Shock
This reason for applying reduced voltage has various different names; it can be called mechanical shock, mechanical stress, or various other names. The effect is the same. When a medium voltage motor is started at full voltage the torque being applied from the motor to the driven load rises to a very high value almost immediately. This can cause damage to the bearings in the motor or the load, the rotor of the motor or to the mechanical coupling method which connects the motor to the load. The load itself can sustain damage depending on what the application may be. In the case of conveyor application if the load is started to quickly the belts of the conveyor can be stretched or broken. If the motor is connected to the load via chains or belts these coupling means can be damaged as well by sudden starting techniques.

Utility Restrictions
As utility power systems continue to be run at maximum capacity the effect of starting medium voltage motors across the line can put stress on the factory’s power distribution system. The lights go dim, process control systems can fail or trip out or you may be restricted as to when and how often you are allowed to start the motor.

Load Related Reasons
By soft starting the load you may see improvements in the way the equipment performs. For example, when a soft starter is applied to an agitator by slowing ramping up the speed of the motor the material being agitated tends to splash less and causes fewer problems than when started across the line. In the case of mill applications the material will start to move slower than when started across the line and cause less wear on the driven load. The ways in which a soft start can improve system performance are only limited to the number of applications that the end user can think of. New uses are being thought of and applied all the time.

Torque Requirements
It is important to reiterate that when the voltage is reduced when starting a motor, so are the current and torque values. It should be apparent that a motor that will not start a load at full voltage, it will not start that same load under reduced voltage conditions. This conflict between torque and current requirements of induction motors is one typical dilemma facing the user of reduced voltage starting equipment. It may be only one of several problems but is the most common and most important.

Reduced voltage starting can be accomplished in several different ways.

Reactor Starting
This method also reduces the voltage, current and torque to the motor according to the reactor tap setting. It is possible to reduce the motor terminal voltage as required by placing a primary reactor in series with the motor windings, for a period during starting. The use of a reactor during starting results in an exceptionally low starting power factor. Reactors must be carefully designed and applied since any saturation in the reactor will produce in-rush currents close to those seen during full voltage starting. Reactor starting has one major advantage; the voltage to the motor is a function of the current taken from the line. It can therefore be assumed that during acceleration the motor voltage will rise as the line current drops. This relationship results in greater accelerating energy at higher speeds and less severe disturbances during the transition to full voltage.

Autotransformer Starting
Autotransformer starting automatically switching between taps of an autotransformer reduces the voltage, current and torque to the motor according to the tap setting used on the autotransformer. There are two very distinctive characteristics of an autotransformer starter.
1. The motor terminal voltage is not a function of load current and remains constant during the
acceleration time.
2. Due to the turn ratio advantages, the primary line current is less than the secondary motor currents. A three-coil autotransformer is connected in a wye configuration and connected to the motor in such a way as to supply reduced voltage to the motor when the line voltage is applied to the Autotransformer. Several sets of taps are usually available to the user to provide different values of reduced voltage (NEMA standards are 80%, 65% and 50% of the full line voltage).

Solid State Reduced Voltage Starting
The use of solid state Reduced Voltage Starting can provide a smooth stepless method of accelerating and smoothly decelerating a squirrel cage induction motor. This type of starting method, when properly applied can provide an efficient and reliable means of smoothly starting and stopping a motor and load. The use of solid-state reduced voltage starting will perform, in most cases, more efficiently than field coupling, eddy current drives and clutches. The stepless ramped acceleration and deceleration capabilities of these types of starter reduces the inrush currents to the motor, eliminating transitional shocks to the load and reducing voltage flicker on the distribution system.

Selection of Appropriate Starting System
The selection of an appropriate starting system requires the reviewer to compare or weigh the importance of several factors.

Cost and Economics:
When determining the starting method, the economics of the decision can also provide important tips to the selection of an appropriate controlling means.

Maintainability:
The capabilities of the mechanical and electrical support facilities and personnel can have an important impact on the starting method determination.

Remote Control Requirements:
As businesses become increasingly more competitive, the reductions in the area of personnel related to the control and operation of industrial processes are becoming dramatic. This required reduction of personnel has subsequently hastened the development of the remote control capabilities of modern motor control equipment. In many cases, production flow and efficiency rate adjustments can be critical to the quality of the end product. For example in the case of remote pumping stations, the ability to control the speed of a booster pump, based on the product in the line at the time, can allow a remote location to monitor and adjust flow rates to maximize the capacity of the pipeline.

Process Control Requirements:
In today’s competitive environment, industry is endeavoring to continually improve processes to produce high quality products, at accelerated periods, at the least possible cost. If the process requires variation of speeds, a controller that will vary the motor speed would be appropriate. If depressed distribution voltage, during motor start cycles, is an issue, a solid state or other reduced voltage starting method may suffice.

Physical size restraints:
The limitations of available physical floor space could be a major concern when retrofitting new equipment into an existing control area. The physical construction of equipment housing the newer technology may not be suitable incorporated within existing facilities. Careful consideration may be required for the removal of heat generated by semi-conducting devices, printed circuit cards, transformers and other electronic control devices. Cooling systems may be needed to aid in the maintenance of a suitable environment for these types of equipment.

Ease of use:
One consideration that is sometimes overlooked is the capabilities of the personnel required to service and maintain the equipment. Simpler more traditional starting means may be suitable where basic personnel training levels are maintained. The simpler relay control logic systems may be adequate for the system configuration required for the specific process.

source: http://www.eng-tips.com/

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Motor Starting Techniques

When large motors are started, noticeable voltage dips or flicker can occur on the consumers wiring system, the utility’s system, or both. Depending on the voltage sensitivity of other connected loads, these voltage dips can be unnoticeable, annoying, or harmful to the equipment. For example, lightbulbs can dim and be annoying to office personnel; however, voltage dips can cause other motor loads to slow down, overheat, and possibly fail. Reduced motor starting equipment is often used to minimize voltage dips and flicker.

The iron and copper wires in large motors need to become magnetized before running at full speed. The inrush current required to start the motor to create the necessary magnetic fields can be as high as 7–11 times the full load current of the motor. Therefore, when large motors start, they often cause low-voltage conditions from voltage drop on the conductors from high-current flows. Utilities normally adopt guidelines or policies for starting large motors. When starting a motor exceeds the utility requirement for voltage dip or flicker (usually set around 3–7%), then special motor starting techniques are usually required.

There are several methods for reducing voltage dip and flicker. Reduced voltage motor starting equipment (i.e., soft starting), such as capacitors, transformers, special winding connections, and other control devices, are commonly used in motor circuitry to reduce the inrush current requirements of large motors during start-up conditions.

The three most common means of providing soft starting or reduced voltage starters on large motors are the following:

1. Resistance is temporarily placed in series with the motor starter breaker contacts or contactor to cause reduced current to flow into the motor when started. This approach can reduce the inrush current to less than five times full load current. Once the motor comes up to full speed, the resistors are shorted out, leaving solid conductors serving the motor power requirements.

2. Wye–delta connection changeover in the motor windings is another very effective way to reduce inrush current. The motor windings are first connected in wye, where the applied voltage is only line to ground; then the motor windings are connected in delta for full voltage and output power.

3. Auto-transformers are sometimes used to apply a reduced voltage to the terminals when started and then switched out to full voltage after the motor reaches full speed. This scheme can be used with motors that do not have external access to the internal windings.

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Transformer Tap Changer

A tap changer is a device fitted to power transformers for regulation of the output voltage to required levels. This is normally achieved by changing the ratios of the transformers on the system by altering the number of turns in one winding of the appropriate transformer/s. Supply authorities are under obligation to their customers to maintain the supply voltage between certain limits. Tap changers offer variable control to keep the supply voltage within these limits. About 96% of all power transformers today above 10MVA incorporate on load tap changers as a means of voltage regulation.

Tap changers can be on load or off load. On load tap changers generally consist of a diverter switch and a selector switch operating as a unit to effect transfer current from one voltage tap to the next. It was more than 60 years ago on load tap changers were introduced to power transformers as a means of on load voltage control.

Tap changers possess two fundamental features:
(a) Some form of impedance is present to prevent short circuiting of the tapped section,
(b) A duplicate circuit is provided so that the load current can be carried by one circuit whilst switching is being carried out on the other.

The impedance mentioned above can either be resistive or reactive. The tap changer with a resistive type of impedance uses high speed switching, whereas the reactive type uses slow moving switching. High speed resistor switching is now the most popular method used worldwide, and hence it is the method that is reviewed in this report.

The tapped portion of the winding may be located at one of the following locations, depending upon the type of winding:
(a) At the line end of the winding;
(b) In the middle of the winding;
(c) At the star point.

The most common type of arrangements is the last two. This is because they give the least electrical stress between the tap changer and earth; along with subjecting the tapings to less physical and electrical stress from fault currents entering the line terminals. At lower voltages the tap changer may be located at either the low voltage or high voltage windings.

Tap changers can be connected to the primary or secondary side windings of the transformer depending on:
- Current rating of the transformer
- Insulation levels present
- Type of winding within the transformer (eg. Star, delta or autotransformer)
- Position of tap changer in the winding
- Losses associated with different tap changer configurations eg. Coarse tap or reverse winding
- Step voltage and circulating currents
- Cost
- Physical size

on-load tap changer

The Consequences Of Transformer Failure

Transformers are one of the more expensive pieces of equipment used in a power system, and the potential consequences of failure can be quite damaging. This has been shown in the past with the political and media attention surrounding blackouts at various locations around the world. Within Australia and New Zealand, the largest cost transformer failures have occurred due to internal winding faults, faulty load tap changers, and failed winding accessories respectively.

Failure of winding accessories includes loose coil clamping bolts, together with internal winding faults and faulty tap changers. These failures affected on average ten transformers per year during the period 1975 to 1995, incurring repair costs of at least $600,000 per year, together with other associated costs. For example, with several elements drawn from an Australian case study and through discussion with engineers at Pacific Power’s Advanced Technical Center, the cost of a generator unit transformer failing has been conservatively estimated at $5.4M. This figure was considered conservative because there are many other factors that could be added on to this figure that are difficult to determine. It is interesting to note the root of these failures appear to have been predominantly design and manufacturing flaws.

Current Maintenance Strategies of Transformer Tap Changers

During the past years and after a number of visits, meetings, lectures and training courses, the conclusion has been reached that proper organization and execution of OLTC maintenance is found only in very few cases.

The frequency of maintenance to on load tap changers is dependent on the condition of the diverter switch and the necessity to maintain the motor drive unit. Maintenance of the diverter switch should be carried out on a cyclic basis, but on transformers where frequency of tap change is high, maintenance may be necessary before the cyclic maintenance becomes due. A certain period should not be exceeded between inspections. When considering inspection periods, serious consideration should be given to the breaking of circulating current which in some cases may exceed the load current.

The diverter switch and tap selector is the only internal moving parts in a transformer. The diverter switch does the entire on load making and breaking of currents, whereas the tap selector preselects the tap to which the diverter switch will transfer the load current. The tap selector operates off load and therefore needs no maintenance. However experience has shown that in some circumstances inspection of selector switches becomes necessary where contacts become misaligned or contact braids in fact fatigueandbreak.

The next segment is a list taken from on what should be carried out during tap changer maintenance;
- Replace contacts in older type tap changers. Modern tap changers rarely require contact replacement; this depends on the characteristics of the tap changer in question. The frequency of diverter switch and motor drive unit inspections can usually be obtained from manufacturer manuals or previous maintenance experience.
- Measuring and recording contact consumption during inspection will give a reasonably accurate life expectancy of the contacts at that present load condition. Therefore this should be done on a regular basis.
- Transition resistors should be checked for continuity and value as an open circuited resistor can result in excessive contact wear.
- Need to equalize rotation lag between the diverter switch and the motor drive unit to ensure minimum spring energisation in the energy accumulator springs.
- The function of relays, interlocks, limit switches and switches should be checked as well as remote indication of tap position.
- Drive shafts and gearboxes must be inspected for radial and axial wear. A large percentage of tap change failures are as a result of drive shaft faults.
- Replace transformer oil with clean, dry oil. Cleaning is only carried out with transformer oil not solvents. Carbon and copper deposits are generally found on horizontal surfaces of the diverter switch as small convection currents in the oil are established each tap change. This results in the carbon being deposited on top of the diverter.

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Calculating Power Factor

As was mentioned before, the angle of this “power triangle” graphically indicates the ratio between the amount of dissipated (or consumed) power and the amount of absorbed/returned power. It also happens to be the same angle as that of the circuit's impedance in polar form. When expressed as a fraction, this ratio between true power and apparent power is called the power factor for this circuit. Because true power and apparent power form the adjacent and hypotenuse sides of a right triangle, respectively, the power factor ratio is also equal to the cosine of that phase angle. Using values from the last example circuit:



It should be noted that power factor, like all ratio measurements, is a unitless quantity.

For the purely resistive circuit, the power factor is 1 (perfect), because the reactive power equals zero. Here, the power triangle would look like a horizontal line, because the opposite (reactive power) side would have zero length.

For the purely inductive circuit, the power factor is zero, because true power equals zero. Here, the power triangle would look like a vertical line, because the adjacent (true power) side would have zero length.

The same could be said for a purely capacitive circuit. If there are no dissipative (resistive) components in the circuit, then the true power must be equal to zero, making any power in the circuit purely reactive. The power triangle for a purely capacitive circuit would again be a vertical line (pointing down instead of up as it was for the purely inductive circuit).

Power factor can be an important aspect to consider in an AC circuit, because any power factor less than 1 means that the circuit's wiring has to carry more current than what would be necessary with zero reactance in the circuit to deliver the same amount of (true) power to the resistive load. If our last example circuit had been purely resistive, we would have been able to deliver a full 169.256 watts to the load with the same 1.410 amps of current, rather than the mere 119.365 watts that it is presently dissipating with that same current quantity. The poor power factor makes for an inefficient power delivery system.

Poor power factor can be corrected, paradoxically, by adding another load to the circuit drawing an equal and opposite amount of reactive power, to cancel out the effects of the load's inductive reactance. Inductive reactance can only be canceled by capacitive reactance, so we have to add a capacitor in parallel to our example circuit as the additional load. The effect of these two opposing reactances in parallel is to bring the circuit's total impedance equal to its total resistance (to make the impedance phase angle equal, or at least closer, to zero).

Since we know that the (uncorrected) reactive power is 119.998 VAR (inductive), we need to calculate the correct capacitor size to produce the same quantity of (capacitive) reactive power. Since this capacitor will be directly in parallel with the source (of known voltage), we'll use the power formula which starts from voltage and reactance:



Let's use a rounded capacitor value of 22 µF and see what happens to our circuit: (Figure below)



Parallel capacitor corrects lagging power factor of inductive load. V2 and node numbers: 0, 1, 2, and 3 are SPICE related, and may be ignored for the moment.



The power factor for the circuit, overall, has been substantially improved. The main current has been decreased from 1.41 amps to 994.7 milliamps, while the power dissipated at the load resistor remains unchanged at 119.365 watts. The power factor is much closer to being 1:



Since the impedance angle is still a positive number, we know that the circuit, overall, is still more inductive than it is capacitive. If our power factor correction efforts had been perfectly on-target, we would have arrived at an impedance angle of exactly zero, or purely resistive. If we had added too large of a capacitor in parallel, we would have ended up with an impedance angle that was negative, indicating that the circuit was more capacitive than inductive.

A SPICE simulation of the circuit of (Figure above) shows total voltage and total current are nearly in phase. The SPICE circuit file has a zero volt voltage-source (V2) in series with the capacitor so that the capacitor current may be measured. The start time of 200 msec ( instead of 0) in the transient analysis statement allows the DC conditions to stabilize before collecting data. See SPICE listing “pf.cir power factor”.

pf.cir power factor
V1 1 0 sin(0 170 60)
C1 1 3 22uF
v2 3 0 0
L1 1 2 160mH
R1 2 0 60
# resolution stop start
.tran 1m 200m 160m
.end

The Nutmeg plot of the various currents with respect to the applied voltage Vtotal is shown in (Figure below). The reference is Vtotal, to which all other measurements are compared. This is because the applied voltage, Vtotal, appears across the parallel branches of the circuit. There is no single current common to all components. We can compare those currents to Vtotal.



Zero phase angle due to in-phase Vtotal and Itotal . The lagging IL with respect to Vtotal is corrected by a leading IC .

Note that the total current (Itotal) is in phase with the applied voltage (Vtotal), indicating a phase angle of near zero. This is no coincidence. Note that the lagging current, IL of the inductor would have caused the total current to have a lagging phase somewhere between (Itotal) and IL. However, the leading capacitor current, IC, compensates for the lagging inductor current. The result is a total current phase-angle somewhere between the inductor and capacitor currents. Moreover, that total current (Itotal) was forced to be in-phase with the total applied voltage (Vtotal), by the calculation of an appropriate capacitor value.

Since the total voltage and current are in phase, the product of these two waveforms, power, will always be positive throughout a 60 Hz cycle, real power as in Figure above. Had the phase-angle not been corrected to zero (PF=1), the product would have been negative where positive portions of one waveform overlapped negative portions of the other as in Figure above. Negative power is fed back to the generator. It cannont be sold; though, it does waste power in the resistance of electric lines between load and generator. The parallel capacitor corrects this problem.

Note that reduction of line losses applies to the lines from the generator to the point where the power factor correction capacitor is applied. In other words, there is still circulating current between the capacitor and the inductive load. This is not normally a problem because the power factor correction is applied close to the offending load, like an induction motor.

It should be noted that too much capacitance in an AC circuit will result in a low power factor just as well as too much inductance. You must be careful not to over-correct when adding capacitance to an AC circuit. You must also be very careful to use the proper capacitors for the job (rated adequately for power system voltages and the occasional voltage spike from lightning strikes, for continuous AC service, and capable of handling the expected levels of current).

If a circuit is predominantly inductive, we say that its power factor is lagging (because the current wave for the circuit lags behind the applied voltage wave). Conversely, if a circuit is predominantly capacitive, we say that its power factor is leading. Thus, our example circuit started out with a power factor of 0.705 lagging, and was corrected to a power factor of 0.999 lagging.

•REVIEW:
•Poor power factor in an AC circuit may be “corrected”, or re-established at a value close to 1, by adding a parallel reactance opposite the effect of the load's reactance. If the load's reactance is inductive in nature (which is almost always will be), parallel capacitance is what is needed to correct poor power factor.

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