Why does the grid operate at 60 HZ in the US, but 50 HZ in Europe?

The frequency of an Alternating Current (AC) system is determined by the construction and operation of the system’s generators.

The generator’s number of pole sets and its speed of rotation determine the output frequency, based on the formula:

Frequency = Number of Pole Sets x RPM / 120

A common mistake made in this calculation is counting the individual magnetic poles in the field and not the pole sets (i.e. North-South pairs). So, for a two-pole generator operating at 3600 RPM, the output would be 60 cycles per second (or 60 HZ). This is a common construction for a gas turbine.

60 HZ = 2 Pole x 3600 RPM / 120

Slower generator speeds are typically seen in steam plants. In these cases, it is common to see a four-pole generator operating at 1800 RPM, which also outputs 60 HZ.

60 HZ = 4 Pole x 1800 RPM / 120

Even slower speeds are seen in hydro generators. A forty-pole generator operating at 180 RPM will still output 60 HZ.

60 HZ = 40 Pole x 180 RPM / 120

As the use of AC evolved from the late 1800’s several different frequencies were tried. The vast majority of these systems were operated as electrical islands, so a standard frequency did not immediately emerge. Frequencies from 16.7 HZ to 133 HZ were used successfully. In 1897 there were some 11 different frequencies used in North America. However, some lighting flicker was seen in frequencies of 40 HZ and lower, so as systems began to be standardized and interconnected, the frequencies of 50 HZ and 60 HZ became the most commonly used. Some anecdotal evidence indicates that Edison’s electrical companies in Europe chose 50 HZ since it was an easily divisible number into 100, and the metric system was based on the number 10. The frequency of 60 HZ was favored by Westinghouse’s operations in the United States, possibly due to the construction of Tesla’s induction motor designs. Westinghouse started off with several installations that operated at 25 HZ and 40 HZ, because these lower frequencies were more compatible with the limitations of turbine blade designs of that era. For example, Westinghouse’s twelve-pole, 250 RPM hydro turbine developed 25 HZ alternating current:

25 HZ = 12 Poles x 250 RPM / 120

As a result of these tests and operations, 60 HZ emerged as the preferred frequency in the United States, with Southern California Edison finally converting to the 60 HZ system in 1948.

What are volt-amps-reactive (VAR)?

VAR is a type of power encountered in a electrical system. It may be power consumed in a power system from the energy used to create fields around inductors. It may also be power that is created in a power system from the electrostatic charge between conductors. Sometimes a system can be operated so that the VAR created from electrostatic charges exactly matches the amount of VAR consumed by the system's inductive fields. This can be a desirable condition.

VAR is a by-product of delivering watts to customers, and VAR is not billable power. This is because current flowing from the source toward the load is used partly to perform work for the customer (watts), and partly to sustain the fields that surround the conductors (VAR). The current that produces the fields is not delivered to the customer and so is not billable. The resultant VAR can be said to flow from the generator toward the load, and then back to the generator.

Some people use the analogy of a wheelbarrow when describing VAR, saying that unless you "waste" some energy lifting the handles of the wheelbarrow, the real work of moving the wheelbarrow can never be done. Similarly, VAR is a reality of power transmission, and a substantial cost of delivering power to customers. A community or industry that contains large inductive loads (irrigation motors, air conditioning compressors, industrial motors, etc) presents a large VAR load to a generator, and this load reduces the amount of billable watts a generator can produce. This large inductive load also forces the utility to install wires of increased size to deliver the watts to customers and deliver the VAR to the line.

Why does voltage rise on a long, unloaded transmission line?

This situation is referred to as the Ferranti Effect, defined as “a rise in voltage occurring at the receiving end of a long transmission line, relative to the voltage at the sending end, which occurs when the line is charged but lightly loaded or unloaded completely.”

This electrical effect was named after Sabastian Ziani de Ferranti (1864-1930), who in 1887 became the chief engineer for London Electric Supply Corporation (LESCo), responsible for the design of their power station at Deptford, England. He designed the building and electrical generating and

distribution system for this installation, which was the largest in the world when it opened in 1891. During the early days of Ferranti’s work at the Deptford Power Station, an anomoly was experienced when transmission line voltages remote from the generator rose to levels that damaged equipment. Intuition led engineers and operators of the time to think that voltage would decay over long distances, but this turned out to be true only when the line is loaded.

The Ferranti Effect occurs when current drawn by the distributed capacitance of the transmission line itself is greater than the current associated with the load at the receiving end of the line. Therefore, the Ferranti effect tends to be a bigger problem on lightly loaded lines, and especially on underground cable circuits where the shunt capacitance is greater than with a corresponding overhead line. This effect is due to the voltage drop across the line inductance (due to charging current) being in phase with the sending end voltages. As this voltage drop affects the sending end voltage, the receiving end voltage becomes greater. The Ferranti Effect will be more pronounced the longer the line and the higher the voltage applied.

The Ferranti Effect is not a problem with lines that are loaded because line capacitive effect is constant independent of load, while inductance will vary with load. As inductive load is added, the VAR generated by the line capacitance is consumed by the load.

How does a phase shifting transformer help operators load and unload transmission lines?

Power flow between two buses can be expressed as:

Power Flow = (Vs*Vr / X) * Sine of the Power Angle.

In other words: power flow (in watts) between two buses will be equal to the voltage on the sending bus multiplied by the voltage on the receiving bus divided by the line reactance, multiplied by the sine of the power angle between the two buses.

This leaves grid operators with at least two options for making a path more conducive to power flow, or if desired, making a path look less conducive to power flow. The two options are to (1)

adjust line reactance and (2) adjust power angle. The Phase Shifting Transformer (PST) affects the second option, i.e. adjusting power angle.

The physical appearance of the PST device is noteworthy, being one of the few transformer types where the physical height and construction of the primary bushings is the same as the secondary bushings. This makes sense since both bushing sets are at the same potential. Internally, the primary voltage of a PST is bussed directly to the secondary bushings, with one important addition. The primary voltage is applied to a delta-wound transformer primary that has adjustable taps that inject “opposing phase” signals. For instance the A-B primary winding has a C phase injection, the B-C winding is injected with A, and the C-A winding is injected with B. These injection points are simultaneously adjustable taps that result in an adjustable shift of power angle.

Since power angle is a direct contributor to the Power Flow formula provided above (in the numerator, not the denominator), changing the PST tap settings can increase power angle making the path more conducive to power flow. The PST tap settings can also decrease power angle making the path less conducive to power flow. (Remember that “power flows downhill on angle”.)

Why is this important? Many transmission paths naturally have less impedance by virtue of their construction and length, and these paths can carry scheduled flow as well as unscheduled flow from parallel (but higher impedance) paths. In some cases these low impedance paths become congested and PST devices and other devices and techniques may be used to relieve the congestion. This is particularly the case in regions where transmission paths are less densely developed, such as the Western United States.

When a turbine generator trips and remains connected to the Grid, it is said to "motor". Does that mean that it reverses mechanical direction?

No. It continues to rotate in the same mechanical direction (i.e. clockwise or counter-clockwise). Here's why the term "motoring" is used.

An AC generator is very much like an AC motor. In fact, lots of old-timers refer to them as simply “AC rotating machines” because their role in an AC circuit can quickly change from one to the other, either intentionally or unintentionally.

Intentional

A hydro pumped-storage facility employs an AC rotating machine, which may be used as a generator or a motor. When energy prices are high the operator will generate current by guiding water from the reservoir, through the penstock and the wicket gates to spin the turbine, which drives the shaft of the magnetic field assembly. However, when the operator determines that energy prices are low the rotating machine may then be operated as a motor in order to pump water back into the reservoir. To do this, not only does the operator stop placing torque on the turbine, but by electrically switching two phases of its electrical connection the rotating machine begins to spin in the opposite direction, and the rotor is no longer a turbine but rather a pump impeller. This motor-driven pump consumes electricity and lifts water back into the reservoir where it can be used for generation when prices are high again.

A generator (especially a hydroelectric generator) may be designed to operate in “condense” mode, sometimes referred to as “motored” mode. In this application, the wicket gates are closed, the volute around the impeller is evacuated of water using pressurized air, and the impeller is left to spin in a relatively dry chamber. Obviously, with the wicket gates closed and no prime mover admitted, no active power (watts) is generated. However, the stator (armature) of the generator is still connected to the grid. Since the rotating electrical field of the grid, applied to the stator, continues to interact with the rotor field, the generator will continue to spin in its original direction, near synchronous electrical speed (e.g. 60 Hz). The mechanical rotation speed of the machine is related to the system frequency and the number of magnetic pole sets in the field assembly, as expressed in the formula N = 120 * F / P. For instance with 16 pole sets (P) and a system frequency of 60 Hz (F), the machine will rotate at 450 RPM (N). The device is referred to “motored” because current no longer flows out, but into the machine. It has become a load. More strategically, though, this generator has become a device that can supply VAR to the system to raise voltage on high load days (“boost”) or absorb VAR to lower voltage on low load days (“buck”), depending on how the field is excited. While the generator in condense mode can be used to help control voltage, in this mode it has no active (billable) watt power output.

Unintentional

Generating plants that experience a prime mover interruption (e.g. loss of steam supply, loss of diesel fuel, etc) typically have control circuitry that signals the generator output breakers to quickly open since prime mover has been lost. In addition, protective relays are installed as a “back-up” to the control scheme. These are called Reverse-Power relays since they are directional current relays that look for current flowing into the generator rather than out of the generator and trip the generator output breakers if needed. Also, if power plant operators forget to manually trip the generator output breakers during a normal plant shutdown, the Reverse-Power relays will do their job as well.

Of note is the fact that if the output breakers are not opened, the machine is still connected electrically to the grid. The rotating electrical field of the grid, applied to the stator, continues to interact with the rotor field, causing it to continue to spin in its original direction near synchronous electrical speed (e.g. 60 Hz). However, it is no longer driven in this direction by the prime mover (i.e. a generator); it is now a motor.

The concern from a plant perspective is that if the prime mover is no longer applying torque to the generator, then power is no longer flowing out. Instead, electrical power from the grid is flowing into a motor. The “driver system” now becomes a “driven system”. Few driver systems can sustain this role reversal. Diesel engines that die and continue to be driven can experience oil starvation and even explosive destruction. Steam turbines that no longer receive steam flow but are driven by the grid’s energy can experience thermal damage, especially in the low pressure turbine stages. In addition, if the excitation system of a generator trips, but the field continues to be rotated, the armature may experience overheating damage.

The reason why the earlier mentioned hydroelectric generator can operate in this motoring (or condense) mode is that hydroelectric generators typically rotate at very slow speeds, while engine-driven or turbine-driven generators typically rotate at speeds as high as 3600 RPM.

How do "new generation" microprocessor-based protective relays verify data integrity?

Data integrity has been a challenge for digital communication systems since their inception.

The simplest form of data checking, used at the dawn of the computer age, was simply data repeat. For example, data would be key-entered by two different clerks and the two sets of data would be compared. If they differed, the orders were researched to determine which one was wrong. If the data matched, the data was considered trustworthy since the likelihood that two different people would make the same error was considered remote. This same method could be used in data communications today. A set of data could be transmitted twice, and compared for quality verification by the receiving computer. The obvious problem with using this method in data communications is that it slows the rate of data transfer due to the repeat time.

To improve data verification, a process was instituted called Parity Checking. In this technique, a block of bits of a predetermined length being transmitted from sender to receiver is marked with a

value that corresponds to its data. Before the data is sent, the sending computer totals the value of all bits set to the value “one”. If the total is even, an additional bit (the parity bit) is set to an agreed upon state (e.g. zero); if the total is odd, the parity bit is set to an agreed upon state (e.g. one). When the receiving computer receives the data and does the same calculation, it should derive the same parity bit value. If it does not, an error has occurred. (Of course, if two errors occurred, the parity bit might be correct, even though the data was corrupted. This system was not perfect.)

Other more sophisticated means of verifying data integrity have evolved over the years, including Checksum calculations that perform mathematical operations on the data values in the block to be transmitted, and then transmit the checksum result along with the data. The receiving computer would then run the same checksum algorithm and the receiver’s result should match the transmitter’s checksum result. If not, the data is corrupted.

In the world of transmission and distribution, data validity in protective relay operations is vital. In many cases, line clearing can be hastened dramatically by using the combined logic of groups of relays, rather than a single relay. As these relays communicate, errors must be eliminated. For readers who are familiar with line relaying schemes, the possibility of sensing and clearing one end of a line within 6 cycles is easily performed from one end of the line, but not necessarily from the other end of the line, unless the relay action is communicated.

In the days of analog protective relays, coordinated operations were conducted using various transfer trip schemes. But today, digital relays are becoming ever more common and the old challenge of data integrity returns. One popular technique used today by microprocessor-based relays is the use of a data block that contains bits with pre-determined values and assignments. As this data block is transmitted among the micro-processor relays in a coordinated relay scheme, actions from a single relay can be shared with the other relays in the scheme and acted upon intelligently using the collective intelligence of the group.

We always in practice to reduce reactive power to improve system efficiency .This are acceptable at some level, if system is purely resistively or capacitance it make cause some problem in Electrical system. AC systems supply or consume two kind of power: real power and reactive power .Real power accomplishes useful work while reactive power supports the voltage that must be controlled for system reliability. Reactive power has a profound effect on the security of power systems because it affects voltages throughout the system. Find important discussion regarding importance about Reactive Power and how it is useful to maintain System voltage healthy

Need of Reactive Power:

Voltage control in an electrical power system is important for proper operation for electrical power equipment to prevent damage such as overheating of generators and motors, to reduce transmission losses and to maintain the ability of the system to withstand and prevent voltage collapse. In general terms, decreasing reactive power causing voltage to fall while increasing it causing voltage to rise. A voltage collapse occurs when the system try to serve much more load than the voltage can support.

When reactive power supply lower voltage, as voltage drops current must increase to maintain power supplied, causing system to consume more reactive power and the voltage drops further . If the current increase too much, transmission lines go off line, overloading other lines and potentially causing cascading failures.

If the voltage drops too low, some generators will disconnect automatically to protect themselves. Voltage collapse occurs when an increase in load or less generation or transmission facilities causes dropping voltage, which causes a further reduction in reactive power from capacitor and line charging, and still there further voltage reductions. If voltage reduction continues, these will cause additional elements to trip, leading further reduction in voltage and loss of the load. The result in these entire progressive and uncontrollable declines in voltage is that the system unable to provide the reactive power required supplying the reactive power demands

Importance of Present of Reactive Power:

Voltage control and reactive-power management are two aspects of a single activity that both supports reliability and facilitates commercial transactions across transmission networks.

On an alternating-current (AC) power system, voltage is controlled by managing production and absorption of reactive power. There are three reasons why it is necessary to manage reactive power and control voltage.

First, both customer and power-system equipment are designed to operate within a range of voltages, usually within±5% of the nominal voltage. At low voltages, many types of equipment perform poorly; light bulbs provide less illumination, induction motors can overheat and be damaged, and some electronic equipment will not operate at. High voltages can damage equipment and shorten their lifetimes.

Second, reactive power consumes transmission and generation resources. To maximize the amount of real power that can be transferred across a congested transmission interface, reactive-power flows must be minimized. Similarly, reactive-power production can limit a generator’s real-power capability.

Third, moving reactive power on the transmission system incurs real-power losses. Both capacity and energy must be supplied to replace these losses.

Voltage control is complicated by two additional factors. First, the transmission system itself is a nonlinear consumer of reactive power,

depending on system loading. At very light loading the system generates reactive power that must be absorbed, while at heavy loading the system consumes a large amount of reactive power that must be replaced. The system’s reactive-power requirements also depend on the generation and transmission configuration.

Consequently, system reactive requirements vary in time as load levels and load and generation patterns change. The bulk-power system is composed of many pieces of equipment, any one of which can fail at any time. Therefore, the system is designed to withstand the loss of any single piece of equipment and to continue operating without impacting any customers. That is, the system is designed to withstand a single contingency. Taken together, these two factors result in a dynamic reactive-power

requirement. The loss of a generator or a major transmission line can have the compounding effect of reducing the reactive supply and, at the same time, reconfiguring flows such that the system is consuming additional reactive power.

At least a portion of the reactive supply must be capable of responding quickly to changing reactive-power demands and to maintain acceptable voltages throughout the system. Thus, just as an electrical system requires real-power reserves to respond to contingencies, so too it must maintain reactive-power reserves.

Loads can also be both real and reactive. The reactive portion of the load could be served from the transmission system. Reactive loads incur more voltage drop and reactive losses in the transmission system than do similar-size (MVA) real loads.

Vertically integrated utilities often include charges for provision of reactive power to loads in their rates. With restructuring, the trend is to restrict loads to operation at near zero reactive power demand (a 1.0 power factor). The system operator proposal limits loads to power factors between 0.97 lagging (absorbing reactive power) and 0.99 leading. This would help to maintain reliability of the system and avoid the problems of market power in which a company could use its transmission lines to limit competition for generation and increase its prices.

Purpose of Reactive Power:

Synchronous generators, SVC and various types of other DER (Distributed energy resource) equipment are used to maintain voltages throughout the transmission system. Injecting reactive power into the system raises voltages, and absorbing reactive power lowers voltages.

Voltage-support requirements are a function of the locations and magnitudes of generator outputs and customer loads and of the configuration of the DER transmission system.

These requirements can differ substantially from location to location and can change rapidly as the location and magnitude of generation and load change. At very low levels of system load, transmission lines act as capacitors and increase voltages. At high levels of load, however, transmission lines absorb reactive power and thereby lower voltages. Most transmission-system equipment (e.g., capacitors, inductors, and tap-changing transformers) is static but can be switched to respond to changes in voltage-support requirements

System operation has three objectives when managing reactive power and voltages. First, it must maintain adequate voltages throughout the transmission and distribution

system for both current and contingency conditions. Second, it seeks to minimize congestion of real-power flows. Third, it seeks to minimize real-power losses. However, the mechanisms that system operators use to acquire and deploy reactive-

power resources are changing .These mechanisms must be fair to all parties as well as effective. Further, they must be demonstrably fair.

What is Reactive Power?

While active power is the energy supplied to run a motor, heat a home, or illuminate an electric light bulb, reactive power provides the important function of regulating voltage.

If voltage on the system is not high enough, active power cannot be supplied.

Reactive power is used to provide the voltage levels necessary for active power to do useful work.

Reactive power is essential to move active power through the transmission and distribution system to the customer

Why Do We Need Reactive Power

Reactive power (VARS) is required to maintain the voltage to deliver active power (watts) through transmission lines.

Motor loads and other loads require reactive power to convert the flow of electrons into useful work.

When there is not enough reactive power, the voltage sags down and it is not possible to push the power demanded by loads through the lines.”

Reactive Power is a Byproduct of Alternating Current (AC) Systems

Transformers, transmission lines, and motors require reactive power Transformers and transmission lines introduce inductance as well as resistance

1. Both oppose the flow of current2. Must raise the voltage higher to push the power through the inductance of the lines3. Unless capacitance is introduced to offset inductance

The farther the transmission of power, the higher the voltage needs to be raised Electric motors need reactive power to produce magnetic fields for their operation

Reactive Power is a Byproduct of Alternating Current (AC) Systems

Transformers, transmission lines, and motors require reactive power Transformers and transmission lines introduce inductance as well as resistance Both

oppose the flow of current must raise the voltage higher to push the power through the inductance of the lines Unless capacitance is introduced to offset inductance

The farther the transmission of power, the higher the voltage needs to be raised Electric motors need reactive power to produce magnetic fields for their operation

How Are Voltages Controlled?

Voltages are controlled by providing sufficient reactive power control margin to “modulate” and supply needs through:

1. Shunt capacitor and reactor compensations2. Dynamic compensation3. Proper voltage schedule of generation.

Voltages are controlled by predicting and correcting reactive power demand from loads

Voltage must be maintained within Acceptable Levels

Under normal system conditions, both peak or off peak load conditions, the voltages need to be maintained between 95% and 105% of the nominal.

Low voltage conditions could result in equipment malfunctions:

1. Motor will stall, overheat or damage2. Reactive power output of capacitors will be reduced exponentially3. Generating units may trip.

High voltage conditions may:

1. Damage major equipment – insulation failure2. Automatically trip major transmission equipment

Voltage and Reactive Power

Voltage and reactive power must be properly managed and controlled to:

1. Provide adequate service quality2. Maintain proper stability of the power system.

Reactive Power and Power Factor

Reactive power is present when the voltage and current are not in phase

1. One waveform leads the other2. Phase angle not equal to 0o3. Power factor less than unity

Measured in volt-ampere reactive (VAR) Produced when the current waveform leads voltage waveform (Leading power factor) Vice versa, consumed when the current waveform lags voltage (lagging power factor)

Reactive Power Limitations

Reactive power does not travel very far. Usually necessary to produce it close to the location where it is needed A supplier/source close to the location of the need is in a much better position to

provide reactive power versus one that is located far from the location of the need Reactive power supplies are closely tied to the ability to deliver real or active power.

Reactive Power Caused Absence of Electrical Supply in Country-A BLACKOUT:

The quality of the electrical energy supply can be evaluated basing on a number of parameters. However, the most important will be always the presence of electrical energy and the number and duration of interrupts.

If there is no voltage in the socket nobody will care about harmonics, sags or surges. A long term, wide-spread interrupt – a blackout leads usually to catastrophic losses. It

is difficult to imagine that in all the country there is no electrical supply. In reality such things have already happened a number of times. One of the reasons

leading to a blackout is reactive power that went out of the control.

When consumption of electrical energy is high, the demand on inductive reactive power increases usually at the same proportion. In this moment, the transmission lines (that are well loaded) introduce an extra inductive reactive power.

The local sources of capacitive reactive power become insufficient. It is necessary to deliver more of the reactive power from generators in power plants.

It might happen that they are already fully loaded and the reactive power will have to be delivered from more distant places or from abroad. Transmission of reactive power will load more the lines, which in turn will introduce more reactive power. The voltage on customer side will decrease further. Local control of voltage by means of autotransformers will lead to increase of current (to get the same power) and this in turn will increase voltage drops in lines. In one moment this process can go like avalanche reducing voltage to zero. In mean time most of the generators in power plants will switch off due to unacceptably low voltage what of course will deteriorate the situation.

In continental Europe most of the power plant is based on heat and steam turbines. If a generation unit in such power plant is stopped and cool down it requires time and electrical energy to start operation again. If the other power plants are also off -the blackout is permanent.

Insufficient reactive power leading to voltage collapse has been a causal factor in major blackouts in the worldwide. Voltage collapse occurred in United States in the blackout of July 2, 1996, and August10, 1996 on the West Coast

While August 14, 2003, blackout in the United States and Canada was not due to a voltage collapse as that term has traditionally used by power system engineers, the task force final report said that” Insufficient reactive power was an issue in the blackout” and the report also “overestimation of dynamics reactive output of system generation ” as common factor among major outages in the United States.

Demand for reactive power was unusually high because of a large volume of long-distance transmissions streaming through Ohio to areas, including Canada, than needed to import power to meet local demand. But the supply of reactive power was low because some plants were out of service and, possibly, because other plants were not producing enough of it.”

PROBLEMS OF REACTIVE POWER:

Though reactive power is needed to run many electrical devices, it can cause harmful effects on your appliances and other motorized loads, as well as your electrical infrastructure. Since the current flowing through your electrical system is higher than that necessary to do the required work, excess power dissipates in the form of heat as the reactive current flows through resistive components like wires, switches and transformers. Keep in mind that whenever energy is expended, you pay. It makes no difference whether the energy is expended in the form of heat or useful work.

We can determine how much reactive power your electrical devices use by measuring their power factor, the ratio between real power and true power. A power factor of 1 (i.e. 100%) ideally means that all electrical power is applied towards real work. Homes typically have overall power factors in the range of 70% to 85%, depending upon which appliances may be running. Newer homes with the latest in energy efficient appliances can have an overall power factor in the nineties.

The typical residential power meter only reads real power, i.e. what you would have with a power factor of 100%. While most electric companies do not charge residences directly for reactive power, it’s a common misconception to say that reactive power

correction has no economic benefit. To begin with, electric companies correct for power factor around industrial complexes, or they will request the offending customer to do so at his expense, or they will charge more for reactive power. Clearly electric companies benefit from power factor correction, since transmission lines carrying the additional (reactive) current to heavily industrialized areas costs them money. Many people overlook the benefits that power factor correction can offer the typical home in comparison to the savings and other benefits that businesses with large inductive loads can expect.

.Most importantly, you pay for reactive power in the form of energy losses created by the reactive current flowing in your home. These losses are in the form of heat and cannot be returned to the grid. Hence you pay. The fewer kilowatts expended in the home, whether from heat dissipation or not, the lower the electric bill. Since power factor correction reduces the energy losses, you save.

As stated earlier, electric companies correct for power factor around industrial complexes, or they will request the offending customer to do so, or they will charge for reactive power. They’re not worried about residential service because the impact on their distribution grid is not as severe as in heavily industrialized areas. However, it is true that power factor correction assists the electric company by reducing demand for electricity, thereby allowing them to satisfy service needs elsewhere. But who cares? Power factor correction lowers your electric bill by reducing the number of kilowatts expended, and without it your electric bill will be higher, guaranteed.

We’ve encountered this with other electric companies and have been successful in getting each of them to issue a retraction. Electric companies do vary greatly and many show no interest in deviating from their standard marketing strategy by acknowledging proven energy saving products. Keep in mind that promoting REAL energy savings to all their customers would devastate their bottom line.

Power factor correction will not raise your electric bill or do harm to your electrical devices. The technology has been successfully applied throughout industry for years. When sized properly, power factor correction will enhance the electrical efficiency and longevity of inductive loads. Power factor correction can have adverse side effects (e.g. harmonics) on sensitive industrialized equipment if not handled by knowledgeable, experienced professionals. Power factor correction on residential dwellings is limited to the capacity of the electrical panel (200 amp max) and does not over compensate household inductive loads. By increasing the efficiency of electrical systems, energy demand and its environmental impact is lessened

Profound effects of Reactive Power in Various elements of Power System:

GENERATION:

An electric-power generator’s primary function is to convert fuel (or other energy resource) into electric power. Almost all generators* also have considerable control over their terminal voltage and reactive-power output.

Payment for the use of this resource is the specific focus of  voltage control from generation service. The ability of   generator to provide reactive support depends on its real-power production. Like most electric equipment, generators are limited by their current-carrying capability. Near rated voltage, this capability becomes an MVA limit for the armature of the generator rather than a MW limitation.

Production of reactive power involves increasing the magnetic field to raise the generator’s terminal voltage. Increasing the magnetic field requires increasing the

current in the rotating field winding. Absorption of reactive power is limited by the magnetic-flux pattern in the stator, which results in excessive heating of the stator-end iron, the core-end heating limit.

The synchronizing torque is also reduced when absorbing large amounts of reactive power, which can also limit generator capability to reduce the chance of losing synchronism with the system.

The generator prime mover (e.g., the steam turbine) is usually designed with less capacity than the electric generator, resulting in the prime-mover limit. The designers recognize that the generator will be producing reactive power and supporting system voltage most of the time. Providing a prime mover capable of delivering all the mechanical power the generator can convert to electricity when it is neither producing nor absorbing reactive power would result in underutilization of the prime mover.

To produce or absorb additional VARs beyond these limits would require a reduction in the real-power output of the unit. Control over the reactive output and the terminal voltage of the generator is provided by adjusting the DC current in the generator’s rotating field .Control can be automatic, continuous, and fast.

The inherent characteristics of the generator help maintain system voltage. At any given field setting, the generator has a specific terminal voltage it is attempting to hold. If the system voltage declines, the generator will inject reactive power into the power system, tending to raise system voltage. If the system voltage rises, the reactive output of the generator will drop, and ultimately reactive power will flow into the generator, tending to lower system voltage. The voltage regulator will accentuate this behavior by driving the field current in the appropriate direction to obtain the desired system voltage.

SYNCHRONOUS CONDENSERS:

Every synchronous machine (motor or generator) with a controllable field has the reactive-power capabilities discussed above.

Synchronous motors are occasionally used to provide dynamic voltage support to the power system as they provide mechanical power to their load. Some combustion turbines and hydro units are designed to allow the generator to operate without its mechanical power source simply to provide the reactive-power capability to the power system when the real-power generation is unavailable or not needed.

Synchronous machines that are designed exclusively to provide reactive support are called synchronous condensers.

Synchronous condensers have all of the response speed and controllability advantages of generators without the need to construct the rest of the power plant (e.g., fuel-handling equipment and boilers). Because they are rotating machines with moving parts and auxiliary systems, they may require significantly more maintenance than static alternatives. They also consume real power equal to about 3% of the machine’s reactive-power rating.

CAPACITORS AND INDUCTORS

Capacitors and inductors (which are sometimes called reactors) are passive devices that generate or absorb reactive power. They accomplish this without significant real-power losses or operating expense. The output of capacitors and inductors is proportional to the square of the voltage. Thus, a capacitor bank (or inductor) rated at 100 MVAR will produce (or absorb) only 90 MVAR when the voltage dips to 0.95 pu

but it will produce (or absorb) 110 MVAR when the voltage rises to 1.05 pu. This relationship is helpful when inductors are employed to hold voltages down.

The inductor absorbs more when voltages are highest and the device is needed most. The relationship is unfortunate for the more common case where capacitors are employed to support voltages. In the extreme case, voltages fall, and capacitors contribute less, resulting in a further degradation in voltage and even less support from the capacitors; ultimately, voltage collapses and outages occur.

Inductors are discrete devices designed to absorb a specific amount of reactive power at a specific voltage. They can be switched on or off but offer no variable control.

Capacitor banks are composed of individual capacitor cans, typically 200 kVAR or less each. The cans are connected in series and parallel to obtain the desired capacitor-bank voltage and capacity rating. Like inductors, capacitor banks are discrete devices but they are often configured with several steps to provide a limited amount of variable control which makes it a disadvantage compared to synchronous motor.

STATIC VAR COMPENSATORS (SVCs)

An SVC combines conventional capacitors and inductors with fast switching capability. Switching takes place in the sub cycle timeframe (i.e., in less than 1/60 of a second), providing a continuous range of control. The range can be designed to span from absorbing to generating reactive power. Consequently, the controls can be designed to provide very fast and effective reactive support and voltage control. Because SVCs use capacitors, they suffer from the same degradation in reactive capability as voltage drops. They also do not have the short-term overload capability of generators and synchronous condensers. SVC applications usually require harmonic filters to reduce the amount of harmonics injected into the power system.

STATIC SYNCHRONOUS COMPENSATORS (STATCOMs)

The STATCOM is a solid-state shunt device that generates or absorbs reactive power and is one member of a family of devices known as flexible AC transmission system (FACTS).

The STATCOM is similar to the SVC in response speed, control capabilities, and the use of power electronics. Rather than using conventional capacitors and inductors combined with fast switches, however, the STATCOM uses power electronics to synthesize the reactive power output. Consequently, output capability is generally symmetric, providing as much capability for production as absorption.

The solid-state nature of the STATCOM means that, similar to the SVC, the controls can be designed to provide very fast and effective voltage control. While not having the short-term overload capability of generators and synchronous condensers, STATCOM capacity does not suffer as seriously as SVCs and capacitors do from degraded voltage.

STATCOMs are current limited so their MVAR capability responds linearly to voltage as opposed to the voltage squared relationship of SVCs and capacitors. This attribute greatly increases the usefulness of STATCOMs in preventing voltage collapse.

DISTRIBUTED GENERATION

Distributing generation resources throughout the power system can have a beneficial effect if the generation has the ability to supply reactive power. Without this ability to control reactive-power output, performance of the transmission and distribution system can be degraded. Induction generators were an attractive choice for small, grid-connected generation, primarily because they are relatively inexpensive. They do not require synchronizing and have mechanical characteristics that are appealing for some applications (wind, for example). They also absorb reactive power rather than generate it, and are not controllable. If the output from the generator fluctuates (as wind does), the reactive demand of the generator fluctuates as well, compounding voltage-control problems for the transmission system. Induction generators can be compensated with static capacitors, but this strategy does not address the fluctuation problem or provide controlled voltage support. Many distributed generation resources are now being coupled to the grid through solid-state power electronics to allow the prime mover’s speed to vary independently of the power-system frequency. For wind, this use of solid-state electronics can improve the energy capture.

For gas-fired micro turbines, power electronics equipment allows them to operate at very high speeds. Photovoltaic’s generate direct current and require inverters to couple them to the power system. Energy-storage devices (e.g., batteries, flywheels, and superconducting magnetic-energy storage devices) are often distributed as well and require solid-state inverters to interface with the grid. This increased use of a solid-state interface between the devices and the power system has the added benefit of providing full reactive-power control, similar to that of a STATCOM.

In fact, most devices do not have to be providing active power for the full range of reactive control to be available. The generation prime mover, e.g. turbine, can be out of service while the reactive component is fully functional. This technological development (solid-state power electronics) has turned a potential problem into a benefit, allowing distributed resources to contribute to voltage control.

TRANSMISSION SIDE:

Unavoidable consequence of loads operation is presence of reactive power, associated with phase shifting between voltage and current.

Some portion of this power is compensated on customer side, while the rest is loading the network. The supply contracts do not require a cosφ equal to one. The reactive power is also used by the transmission lines owner for controlling the voltages.

Reactive component of current adds to the loads current and increases the voltage drops across network impedances. Adjusting the reactive power flow the operator change voltage drops in lines and in this way the voltage at customer connection point. The voltage on customer side depends on everything what happens on the way from generator to customer loads. All nodes, connation points of other transmission lines, distribution station and other equipment contribute to reactive power flow.

A transmission line itself is also a source of reactive power. A line that is open on the other end (without load) is like a capacitor and is a source of capacitive (leading) reactive power. The lengthwise inductances without current are not magnetized and do not introduce any reactive components.

On the other hand, when a line is conducting high current, the contribution of the lengthwise inductances is prevalent and the line itself becomes a source of inductive (lagging) reactive power. For each line can be calculated a characteristic value of power flow Sk.

If the transmitted power is above Sk, the line will introduce additionally inductive reactive power, and if it is below Sk, the line will introduce capacitive reactive power. The value of Sk depends on the voltage: for 400 kV line is about 32% of the nominal transmission power, for 220 kV line is about 28% and for 110 kV line is about 22%. The percentage will vary accordingly to construction parameters.

The reactive power introduced by the lines themselves is really a nuisance for the transmission system operator. In the night, when the demand is low it is necessary to connect parallel reactors for consuming the additional capacitive reactive power of the lines. Sometimes it is necessary to switch off a low-loaded line (what definitely affect the system reliability). In peak hours not only the customer loads cause big voltage drops but also the inductive reactive power of the lines adds to the total power flow and causes further voltage drops.

The voltage and reactive power control has some limitations. A big part of reactive power is generated in power plant unites. The generators can deliver smoothly adjustable leading and lagging reactive power without any fuel costs.

However, the reactive power occupies the generation capacity and reduces the active power production. Furthermore, it is not worth to transmit reactive power for long distance (because of active power losses). Control provided “on the way” in transmission line, connation nodes, distribution station and other points requires installation of capacitors or\and reactors.

They are often used with transformer tap changing system. The range of voltage control depends on their size. The control may consist e.g. in setting the transformer voltage higher and then reducing it by reactive currents flow.

If the transformer voltage reaches the highest value and all capacitors are in operation, the voltage on customer side cannot be further increase. On the other hand when a reduction is required the limit is set by maximal reactive power of reactors and the lowest tap of transformer.

Voltage & Reactive Power Planning and Assessment Practices:

(1) Key Principles:

Reactive power cannot be transmitted over a long distance or through power transformers due to excessive reactive power losses.

Reactive power supply should be located in close proximity to its consumption. Sufficient static and dynamic voltage support is needed to maintain voltage levels

within an acceptable range. Sufficient reactive power reserves must be available to regulate voltage at all time

(2) Key Implications:

Metering must be in place and maintained to capture actual reactive consumption at various points.

Transmission and Distribution planners must determine in advance the required type and location of reactive correction.

Reactive power devices must be maintained and functioning properly to ensure the correct amount of reactive compensation.

Distribution reactive loads must be fully compensated before transmission reactive compensation is considered.

(3) Transmitting Reactive Power

Reactive power cannot be effectively transmitted across long distances or through power transformers due to high I2X losses

Reactive power should be located in close proximity to its consumption.

(4) Static vs. Dynamic Voltage Support

The type of reactive compensation required is based on the time needed for voltage recovery.

Static Compensation is ideal for second and minute responses. (Capacitors, reactors, tap changes).

Dynamic Compensation is ideal for instantaneous responses. (condensers, generators) A proper balance of static and dynamic voltage support is needed to maintain voltage

levels within an acceptable range.

(5) Reactive Reserves during Varying Operating Conditions

Ideally, the system capacitors, reactors, and condensers should be operated to supply the normal reactive load.

As the load increases or following a contingency, additional capacitors should be switched on or reactors removed to maintain acceptable system voltages.

The reactive capability of the generators should be largely reserved for contingencies on the EHV system or to support voltages during extreme system operating conditions.

Load shedding schemes must be implemented if a desired voltage is unattainable thru reactive power reserves.

(6) Voltage Coordination

The reactive sources must be coordinated to ensure that adequate voltages are maintained everywhere on the interconnected system during all possible system conditions.

Maintaining acceptable system voltages involves the coordination of sources and sinks which include:

1. Plant voltage schedules2. Transformer tap settings3. Reactive device settings4. Load shedding schemes.

The consequences of uncoordinated operations would include:

1. Increased reactive power losses2. A reduction in reactive margin available for contingencies and extreme light load

conditions3. Excessive switching of shunt capacitors or reactors4. Increased probability of voltage collapse conditions.

(7) Voltage Schedule

Each power plant is requested to maintain a particular voltage on the system bus to which the plant is connected.

The assigned schedule will permit the generating unit to typically operate:

1. In the middle of its reactive capability range during normal conditions2. At the high end of its reactive capability range during contingencies3. “Under excited” or absorb reactive power under extreme light load conditions.

(8) Transformer Tap Settings

Transformer taps must be coordinated with each other and with nearby generating station voltage schedules.

The transformer taps should be selected so that secondary voltages remain below equipment limits during light load conditions.

(9) Reactive Device Settings

Capacitors on the low voltage networks should be set to switch “on” to maintain voltages during peak and contingency conditions. And

“Off” when no longer required supporting voltage levels.

(10) Load Shedding Schemes

Load shedding schemes must be implemented as a “last resort” to maintain acceptable voltages.

(11) Voltage and Reactive Power Control

Requires the coordination work of all Transmission and Distribution disciplines. Transmission needs to:

1. Forecast the reactive demand and required reserve margin2. Plan, engineer, and install the required type and location of reactive correction3. Maintain reactive devices for proper compensation4. Maintain meters to ensure accurate data5. Recommend the proper load shedding scheme if necessary.

Distribution needs to:

1. Fully compensate distribution loads before Transmission reactive compensation is considered

2. Maintain reactive devices for proper compensation3. Maintain meters to ensure accurate data4. Install and test automatic under voltage load shedding schemes