Showing posts with label Power System. Show all posts
Showing posts with label Power System. Show all posts

Lightning Phenomena

Lightning Arrester or surge suppressor is the protective device used in every electric substation (small or large) which protects the substation from lightning and other electrical transients. In the next article we will discuss about lightning arrester. Before we discuss about lightning arrester it is important to learn  some basics about the lightning phenomena. After all it is a very interesting subject. In last few centuries many scientists, engineers, philosophers and others have shown considerable interest in studying the lightning phenomena (perhaps due to the curiosity gathered from the childhood). The scientific theories formulated by them differ in some some aspects. However still there is much agreements between the studies carried out. For example in almost all the studies it is mentioned that in most cases the upper part of the cloud is positively charged and the lower part is negatively charged. (The way it is charged or the rise in charge quantity is explained differently by different researchers). We will discuss this in a manner which is well accepted and simple to understand.

See the figure below. Consider the cloud whose upper part is positively charged and lower part is negatively charged. Due to this the portion of earth below the cloud becomes positively charged. As the charge on the cloud increases, so also the charge induced on the ground below the cloud increases. This situation results in rise in the electric field intensity in the space between the cloud and the ground. Finally electric breakdown of the space between the cloud and ground takes place which is seen in the form of an electric discharge.

The sequence of lightning stroke is as follows. As the charge on the lower portion of the cloud increases the electric field increases. This results in ionization of air in the vicinity of area with more charge concentration. Then an ionized path or streamer (stream of charges) develops. This is called as stepped leader(see below). The leader proceeds downward in steps of tens of meters with a speed of about one tenth the speed of light. Several leaders may originate from the cloud at different parts of the clouds.

The ground objects mainly the taller structures also ionize the air in the vicinity of its top and releases a stream of positive charge. That is to say the upward moving leaders usually originates from taller structures (see above).

Finally the downward leader from the cloud may connect the upward moving leader. It results in a ionised conducting path giving rise to heavy current flow through this ionized path. This is called the return stroke. This lightning stroke may carry hundreds of kilo-ampere of current and extremely bright.  This is known as direct lightning stroke. It may hit transmission lines and other electrical equipment developing voltage surge of very high peak value and causing extensive damage to the equipment or catches fire.

Sometimes another form of surge develops in the overhead line. See the figure below in which there are two charged clouds.

The portion of the transmission line below the cloud develops positive charge by electrostatic induction. If the lightning discharge takes place between the clouds then sudden disappearance or rearrangement of charge on the clouds results in instant release of induced charge from the line portion (see figure below). This phenomenon gives rise to travelling voltage waves (due to moving charges)  to both directions of the line (surges are shown side by). This voltage surges hit the electric equipment at line terminating points which may be a substation or generating station. The surges are equally harmful to line insulators. This is the induced voltage surge due to electrostatic induction.

Voltage surges may also develop due to magnetic induction. Due to the high current in the lightning stroke  and/or lines due to surge current, strong magnetic field is created around it. Any conductor experiencing this magnetic field  variation will develop voltage surge.

CT And VT Comparison And Connection

In the last two articles we discussed about the Voltage Transformer(VT) and Current Transformer(CT). Here we will discuss few more facts about the instrument transformers and compare the two. In industry the voltage transformer is also called as Potential transformer(PT). In a power system representation. CT and VT or PT are shown symbolically. Below are the symbols commonly used for VT and CT. Sometimes VT is also represented by two overlapping circles (as in power transformer). Also similar to power transformer, small round dots are used for identification of polarities of the instruments. Proper polarities identification is important for connection of instrument transformers.

Here below we compare some important characteristics of CT and VT
  • A Voltage Transformer(VT) transform high voltage of the primary side to low voltage and Current Transformer(CT) Transform  high primary side current to low current. These low values of voltage and current can be readily used by the measuring and protection instruments.
  • The instrument transformers insulate the low voltage measuring and protection instruments from the high voltage side. It enhances safety for the personnel at the low voltage control and protection side.
  • The instrument transformers make it possible for standardization of instruments and relays etc.
  • VT is connected between the line and ground or between the lines(see fig-B). In high voltage application it is usually connected between the line and ground. A CT is connected in series with the line (fig-B).
  • When energized from the primary side the secondary of CT should never be kept open and secondary terminals should be shorted. The VT secondary should never be shorted. So a fuse is not inserted in the secondary of CT. But a fuse can be inserted in the primary or secondary side of VT.
  • The primary of CT carries the actual current of the Line whose value of current is to be measured or sampled. Hence the primary side of CT is comprised of thick conductor to carry line current and the secondary side has several turns of conductors of thinner cross section. In a VT the primary side voltage is high  so there are large numbers of turns in the primary side of thinner conductor. The secondary side of VT has few turns of conductor of large cross sectional area. The secondary side carries large current for supply to the burden.
  • For a VT the ideal transformer Law, Vp/Np = Vs / Ns is important. For a CT the transformer Law IpNp =IsNs is important. The design of the VT and CT should be such so that these ideal laws are satisfied to good accuracy for the respective instrument transformers. 

CT and PT Connection

You have studied in the school that the ammeter should be connected in series with the load and voltmeter should be connected across the terminals of the load for which the voltage is to be measured. Similarly A CT is connected in series with the load or line and the VT is connected between the line and ground (or between the terminals of load or source).  See the figure below. In the figure is a simple system with an AC source and a load connected by a line. This is the HV system shown in thick line. The connection of CT, VT and other measuring and protection instruments are shown with thinner lines. V and I are the voltmeter and ammeter connected to secondary sides of VT and CT respectively for measurement of voltage between the lines and current I flowing through the line. R is the Relay, one is connected across the secondary of VT and another is in series with CT secondary.  The relay connected in VT is the voltage operated type and the one connected in the secondary of CT is current operated type. The VT is also shown as connected to the pressure coil of the watt meter and the CT is connected to the current coil of the same watt meter. The VT and CT can be connected to many measuring and/or protection devices. But the sum of the burdens of the devices should not exceed the rated burden of the Instruments.

VT and CT are the measuring instruments and the main purpose is to measure the circuit condition or parameters. So the connection of the instrument transformers should not influence or alter the original circuit condition. It follows that the CT is desired to have very little impedance (or resistance) across its terminals. So that the CT in series with the line should not result in any significant voltage drop across its terminals. The current flowing in the secondary of the CT  does not influence the primary side current.  The primary side current is solely determined by the load impedance, source voltage and of course the line parameters.

A voltage transformer is connected between line and  ground. It is desired to have very high impedance. A low impedance results in comparatively large current flow in VT primary and can considerably alters the original circuit condition which is not desired. Otherwise we can say that the voltage transformer should have negligible loading effect on the main circuit. In figure-B, the values of Iz and I should not show any noticeable difference due to connection of VT and CT.

 In fig-C is shown the SLD of the simple system illustrating symbolic connection of CT and VT.

Air Blast Circuit Breaker (ABCB)

We have so far discussed three main types of circuit breakers. These are Vacuum Circuit Breaker, Gas Circuit Breaker or SF6  Circuit Breaker (GCB) and Oil Circuit Breaker. The other type of circuit breaker that we discuss here is Air Blast Circuit Breaker(ABCB). This type of breakers are also becoming obsolete. Once Air Blast type of breakers were preferred in Extra High Voltage substations. Now it is difficult to find new HV/EHV substations equipped with Air Blast Circuit Breakers.

One should not be confused between Air Circuit Breaker and Air Blast Circuit Breaker. Air Circuit Breakers are usually used in low voltage applications below 450 volts. You can today find these in Distribution Panels (below 450 volts). Air Blast Circuit Breakers are high capacity breakers and can be seen in old substations mainly above 132 kV. The working principle of these two circuit breakers are quite different. Here we will only discuss the working of ABCB.

In Air Blast Circuit Breaker, air at high pressure is blast upon the arc formed between the contacts. The air blast blows away the ionized air between the contacts.

See the Sketches (Figs-A and B) illustrating the arc extinction process of the axial blast type breaker . The contacts are in closed position by spring pressure. For opening the contacts. Air at high pressure from the air receiver (Fig-C) is blasted to the interruption chamber. This pressure exceeds the spring pressure and pushes the moving contact away from the fixed contact. This opens the contacts and air at high pressure passes through the nozzle and port to the atmosphere. This axial flow of air at high speed extinguishes the arc within 2 or 3 cycles of current wave and ionized gas is blown away.  Then the port is closed by the moving contact arm(Fig-B)  and the space between the contacts is filled with fresh air at high pressure. This enables the breaker to withstand high Transient recovery Voltage (TRV). Compare Fig-A with Fig-B. In Fig-B the arc is extinguished and spring is in compressed state.

To close the contacts, a valve arrangement lets the air from the chamber to pass to the outside atmosphere. This makes the spring pressure to close the fixed and moving contacts.

Some main advantages of the Air Blast Circuit Breaker(ABCB) are:
  • Arc extinction is very fast. Hence it is suitable for frequent opening and closing operation.
  • Due to refilling of separated contacts space by fresh air at high pressure,  the separation requirement between the contacts is quite less in comparison to OCB. This makes the size of the breaker smaller.
  • The ionized gas flushed out to the atmosphere. Hence unlike OCB here the arc quenching medium does not deteriorate with time. This eliminates some maintenance burden.
  • It is non-inflammable.
  • Finally one important advantage is that in ABCB the arc quenching depends on the high pressure air which is obtained from a compressor, an external source. So in case of ABCB the arc extinction or arcing time does not depends upon the arc current. (In case of OCB the arcing time depends on the current to be interrupted).
  • The breaker breaking capacity depends upon the external source, the high pressure air.
The Air Blast Circuit Breakers has some disadvantages. The important one is that  Air Blast Circuit Breakers  require a compressor plant (not shown in Fig-C) which requires regular maintenance. Hence ABCB is not economical for low voltage applications. There are other issues like current chopping and restriking voltage which requires to be handled by proper design and damping mechanism.

In last few articles we have discussed the working principles of all the major types of breakers used in High Voltage and Extra High Voltage Substations. Perhaps this is enough in developing some basic concepts on an important substation equipment like Circuit Breaker. In subsequent articles we will discuss some other equipment used in HV/EHV substations.

Oil Circuit Breaker

We already discussed Vacuum Circuit Breaker and SF6 Circuit Breaker. In modern power systems these two types of circuit breakers are mainly used for high voltage application. While vacuum breakers are mainly used for voltage upto 38 kV, SF6 breakers are used starting from distribution voltage at 11 kV upto 765 kV and 1200 kV level.  Although the use of oil breaker has reduced very much one can still find oil CB in many installations. So I liked to write a little about oil circuit breaker in one article.

Oil Circuit Breakers (OCB) can be categorised into two types. One is Bulk Oil Circuit Breaker (BOCB) and the other type is Minimum Oil Circuit Breaker (MOCB). MOCB type is also called as Low Oil Circuit Breaker.

Bulk Oil Circuit Breaker (BOCB)

The Bulk Oil CB design is very simple (Fig-A). In Fig-A the arc control device between the fixed and moving contacts is not shown, so making the sketch even simpler. This type of circuit breaker uses a steel tank containing oil and the contacts are immersed in the oil. The steel tank is earthed (dead tank type). In this type construction the oil requirement is more as the oil is required to provide insulation to the contacts from the steel tank and insulation between the contacts(in open state). The oil also serves as the medium for extinguishing the arc formed when the moving contact separates from fixed contact. When the contacts separate, arc is formed between the contacts. The arc gives rise to formation of gas in the oil which initiates oil circulation. This phenomena helps in extinguishing the arc so breaking the circuit. For higher voltage this very simple principle cannot be much effective. So an arc control device is usually used to facilitate arc extinction process.

The BOCB is available as single tank type or three tank type. Usually for lower voltage use, below 38 kV, single tank type is adopted with barrier between the phases.  For higher voltage application three separate tanks are used.

Minimum Oil Circuit Breaker

If you visit an old substation, having BOCB installed, you immediately recognise the oversize Circuit Breaker. As explained above, BOCB is large in size and requires more space. 

Minimum Oil Circuit Breakers (MOCB) require less oil as the purpose here is only to extinguish the arc and not for providing insulation to the contact. Arc interruption takes place inside the Interrupter. The whole system is placed inside the porcelain housing. Because of this insulating porcelain the insulation requirement of contacts is reduced very much. This is the reason of its smaller size. As such the MOCBs are of  live tank outdoor type design and mainly used for voltage levels above 38 kV.

The oil circuit breakers have some severe disadvantages. The main disadvantage is that the OCB can explode causing harm to the personnel and other equipment of the system. The tank type design is very bulky so making it difficult for transportation and handling and requires more space. The OCB requires more maintenance in comparison to vacuum and SF6 breakers. Irrespective of these few disadvantages the OCBs are not going to vanish within few years.


SF6 Circuit Breaker Working Principle

At this point we are aware that the medium in which arc extinction of the circuit breaker takes place greatly influences the  important characteristics and life of the circuit breaker. In the last article the working of a vacuum circuit breaker was illustrated. We already know that the use of vacuum circuit breaker is mainly restricted to  system voltage below 38 kV. The characteristics of vacuum as medium and cost of the vacuum CB does not makes it suitable for voltage exceeding 38 kV. In the past for higher transmission voltage Oil Circuit Breaker (OCB) and Air Blast Circuit Breaker (ABCB) were used. These days for higher transmission voltage levels  SF Circuit Breakers are largely used. OCB and ABCB have almost become obsolete.  In fact in many installations SF6  CB is used for lower voltages  like 11 kV, 6 kV etc..

Sulphur Hexafluoride symbolically written as SF is a gas which satisfy the requirements of an ideal arc interrupting medium. So SF6  is extensively used these days as an arc interrupting medium in circuit breakers ranging from 3 kv  upto 765 kv class. In addition to this SF6 is used in many electrical equipments for insulation. Here first we discuss in brief, some of the essential properties of  SF6 which is the reason of it's extensive use in circuit breakers

  • SF6 gas has high dielectric strength which is the most important quality of a material for use in electrical equipments and in particular for breaker it is one of the most desired properties. Moreover it has high Rate of Rise of dielectric strength after arc extinction. This characteristics is very much sought for a circuit breaker to avoid restriking.
  • SF6 is colour less, odour less and non toxic gas.
  • SF6  is an inert gas. So in normal operating condition the metallic parts in contact with the gas are not corroded. This ensures the life of the breaker and reduces the need for maintenance.
  • SF6 has high thermal conductivity which means the heat dissipation capacity is more. This implies greater current carrying capacity when surrounded by SF6 .
  • The gas is quite stable. However it disintegrates to other fluorides of Sulphur in the presence of arc. but after the extinction of the arc the SF6  gas is reformed from the decomposition.
  • SF6 being non-flammable so there is no risk of fire hazard and explosion. 
The construction and working principles of SF6 circuit breaker varies from manufacturer to manufacturer. In the past double pressure type of SF6 breakers were used. Now these are obsolete. Another type of SF6 breaker design is the self blast type, which is usually used for medium transmission voltage. The Puffer type SF6 breakers of single pressure type are the most favoured types prevalent in power industry.  Here the working principle of Puffer type breaker is illustrated (Fig-A).

As illustrated in the figure the breaker has a cylinder and piston arrangement. Here the piston is fixed but the cylinder is movable. The cylinder is tied to the moving contact so that for opening the breaker the cylinder along with the moving contact moves away from the fixed contact (Fig-A(b)). But due to the presence of fixed piston the SF6 gas inside the cylinder is compressed. The compressed  SF6 gas flows through the nozzle and over the electric arc in  axial direction. Due to heat convection and radiation the arc radius reduces gradually and the arc is finally extinguished at current zero. The dielectric strength of the medium between the separated contacts increases rapidly and restored quickly as fresh SF6 gas fills the space. While arc quenching, small quantity of SF6 gas is broken down to some other fluorides of sulphur which mostly recombine to form  SF6  again. A filter is also suitably placed in the interrupter to absorb the remaining decomposed byproduct.

The gas pressure inside the cylinder is maintained at around 5 kgf per sq. cm. At higher pressure the dielectric strength of the gas increases. But at higher pressure the SF6 gas liquify at higher temperature which is undesired. So heater is required to be arranged for automatic control of the temperature for circuit breakers where higher pressure is utilised. If the SF6 gas will liquify then it loses the ability to quench the arc.

Like vacuum breaker, SF6 breakers are also available in modular design form so that two modules connected in series can be used for higher voltage levels. SF6 breakers are available as both live tank and dead tank types. In Fig-B above a live tank outdoor type 400 kV SF6 breaker is shown.

Vacuum Circuit Breaker

The Vacuum Circuit Breakers (VCB) are particularly advantageous for use in the voltage range 3 kV to 38 kV. In the Vacuum Circuit Breaker the arc interruption takes place in vacuum in the interrupter. The pressure inside the vacuum interrupter is maintained below 10-4 torr. At this low pressure very few molecules are available inside the interrupter chamber. This is one desired characteristic of the interrupting medium for more efficient arc quenching.

For opening the circuit breaker, the operating mechanism separates the moving contact from the fixed contact inside the interrupter. Just at the point of contact separation, a very small amount of metal vaporizes from contact tip and arc is drawn between the contacts. Current flows between the contacts through this arc. Due to the sinusoidal nature of the AC current, the current after reaching the maximum value decreases so reducing the vapour emission. Near zero value of the sinusoidal current wave the arc is extinguished. The metal vapour is deposited on the condensing shield  (see Fig-A). The space inside the interrupter being high vacuum, very little ions are available between the electrodes/contacts. So after arc extinction the space between the contacts regains dielectric strength very rapidly which is the most desired characteristics of the arc quenching medium. Due to the rapid regaining of dielectric strength of vacuum inside the interrupter the re-striking does not takes place. In the figure below is shown the main constructional features of a Vacuum Circuit Breaker (VCB).

The vacuum condensing shield is used so that the metallic vapour does not condenses on the enclosure glass. In the absence of the shield the metallic vapour condenses on the glass and gradually the glass becomes conducting, so that the insulation between the moving and fixed contacts is lost in the open condition of the breaker. The metallic bellow makes it possible to maintain vacuum inside the interrupter chamber while allowing the movement of moving contact for separation from the fixed contact. One side of the bellows is welded to the moving contact stem as shown while the other side is welded to the interrupter end plate. The contact surface is so designed that the arc between the contacts diffuse. The arc spread to the sides of the contact surfaces. Diffusion of arc reduces its strength hence the arc quenching is facilitated. The main requirements of the contact material is, very high electrical and thermal conductivity, low contact resistance and high melting point.

Advantages of VCB
  • The vacuum interrupters have long life. 
  • Unlike oil CB (OCB) or air blast CB (ABCB), the explosion of VCB is avoided. This enhances the safety of the operating personnel. 
  • No fire hazard.
  • The vacuum CB is fast in operation so ideal for fault clearing. VCB is suitable for repeated operation. 
  • Vacuum circuit breakers are almost maintenance free. 
  • Due to the rapid gain of dielectric strength of vacuum interrupter, the separation required between the moving contact from fixed contact is of the order of few millimetre. This makes the VCB compact.
  • VCB is light weight.
  • No exhaust of gas to the atmosphere.
  • Quiet operation.
Disadvantages of VCB
  • The main disadvantage of VCB is that it is uneconomical for use of VCB at voltages exceeding 38 kV. The cost of the breaker becomes prohibitive at higher voltages. This is due to the fact that at high voltages (above 38 kV) more than two numbers of interrupters are required to be connected in series.
  • Advance technology is used for production of vacuum interrupters. 
More over the vacuum interrupters production is uneconomical if produced in small quantities.Vacuum interrupters are used in metal clad switchgear and also in porcelain housed circuit breakers.
Vacuum interrupters have been successfully used in some countries for circuit breaker rating above 132 kV. The interrupters of a three phase vacuum CB is shown below.

Breaker Switching Phenomena and TRV

Here we discuss the phenomena associated with breaker switching. One will be able to better appreciate this article if little knowledge of Arcing in Circuit Breaker is developed first. So before proceeding further it is better to go through the above link. At this point perhaps we are aware that it is important to understand the switching and arc quenching phenomena in a Circuit Breaker. Here is illustrated the main concept of the subject without much attention to the mathematics involved. Of course as usual the aim is to keep the material simple.

Circuit breaker switching results in either breaking the circuit or making the circuit. After a circuit breaker is closed or opened the configuration of the system changes. For example by opening a breaker a part of the network may be de-energised or isolated or a load may be disconnected. The breakers also automatically open when a fault happens in the network. On occurrence of fault the trip signal initiates breaker mechanism so that the breaker contacts separate, and arc is formed between the contacts. The arc is extinguished at current zero. But there are  chances of re-striking, how and why restrike, is the main subject of discussion here. The analysis is not universal. Although one analysis can not be applied to every circuit configuration or situation but still it is enough for developing the main concept of successful arc extinction. Here for illustration we have chosen the case when a fault happens in a line and the line breaker trips to isolate the fault from the source. For illustration we have chosen this case because under faulted condition the breaker is under severe stress which the breaker design should meet to successfully operate. The figure-A below is the circuit with  equivalent elements and fault illustrated.

In the circuit shown, L is the equivalent inductance of the line which may include the transformer reactance up to the breaker. The line resistance being small is first neglected. The impact of line resistance is also important and will be revealed later. C is the equivalent capacitance at the breaker terminal towards source side. The capacitance is mainly due to the equipment bushings. When the arc between the breaker poles is extinguished, another capacitance between the poles exist. It should be realized that due to the dead fault, the capacitance between the poles also contribute to the capacitance C.

Let a fault happens at the load end as shown. The fault is dead short circuit (shown by double headed arrow). The breaker receives trip signal, the tripping mechanism operates and the breaker moving contact starts moving away from the fixed contact. An arc is formed between the contacts. The fault current is fed through the arc as long as arc exist. Being a dead short circuit the fault resistance is assumed zero. So the equivalent circuit of this faulted case is redrawn as in Fig-B(i).

When feeding fault the circuit is purely inductive (ignoring little resistance). The circuit being purely inductive, the current lags the voltage wave V by 90 degrees. The voltage across the poles of the breaker is the voltage drop across the arc. In a high voltage circuit this arc voltage is negligible in comparison to line voltage. So we neglect the voltage drop across the arc. Hence, during arcing the voltage difference between the poles of the circuit breaker is the voltage drop across the arc. Due to dead short circuit voltage across the fault is assumed zero. Hence the voltage across the capacitance is almost same as voltage difference between the poles of the breaker which is zero (Vb = 0). The wave shapes of system voltage, current and voltage across the poles of breaker (violet color) is shown in Fig-C (upto point O).

The arc is extinguished at current zero (point O in Fig-C).  Just at the instant of current zero the arc is extinguished but supply voltage is at its peak. It should be clear that the voltage across the poles of breaker is the voltage across the capacitance C. So just at the point of arc extinction (point O) the voltage across the poles of the breaker is same as the voltage across the capacitance which is zero.

For the new state that is after the point of arc extinction (after point O in fig-C) the circuit is shown in Fig-B(ii) with direction of current shown. In this new configuration the voltage across the capacitance which is the same as the voltage across the breaker terminals tries to approach the system voltage by flow of current through the inductance and capacitance (neglecting the resistance of line). The voltage across the capacitance which is the voltage across the breaker poles approaches the system voltage in an oscillatory manner due to the formation of series LC circuit (See Fig-C). As already said at point 'O' current is zero and arc is extinguished. Before point 'O' the voltage across the poles (same as arc voltage) being negligibly small is shown zero.

The frequency of oscillation of the transient is very high in comparison to the power frequency at 60 Hz or 50 Hz . If fo is the frequency of oscillation of the transient voltage then,

fo= 1 / [2π√(LC)]

 ωo= 2πfo

The voltage across the poles of breaker after arc extinction is called as the recovery voltage. But the Transient part just after current zero is called as Transient Recovery Voltage (TRV). After the transient vanishes within few microseconds the voltage across the poles  is called Recovery Voltage which is at power frequency. Look at figure-C how the voltage across the poles (violet) approaches system voltage. It should be noted that the Transient Recovery Voltage is also known as Restriking Voltage.

It is observed that the oscillatory transient is superimposed on power frequency wave shape to give the resultant voltage shape. Due to the low values of both L and C the frequency of oscillation is very high in comparison to power frequency at 60 Hz or 50 Hz. from the figure-C it is shown that the amplitude of oscillation of the transient dies out gradually. Gradual die out of transient is called damping which is due to the presence of the small line/equipment resistance. Due to this small value of resistance we have already considered the circuit as almost purely inductive so fault current lags voltage by 90 degrees.

From the figure it is observed that the voltage increases very rapidly from zero to the first peak. The rate of rise of this Transient Recovery Voltage and the value of the peak voltage are very important for successful arc quenching ability of breaker.

If rate of rise of recovery voltage is higher than the rate of gain in dielectric strength of the medium between the breaker contacts then restrike will happen and arc is again formed between the contacts, feeding the fault for another half cycle at least till next current zero is encountered. Otherwise if rate of gain of dielectric strength is more than rate of rise of recovery voltage than there will be no restrike and no further arc formation. The interrupter should also be able to withstand the peak of Transient Recovery Voltage and Recovery Voltage at power frequency. Otherwise breakdown between the contacts may takes place and arc is again formed. The arc is successfully extinguished if restrike does not happen.

TRV and Recovery voltage depends upon the characteristics and configuration of the circuit.

  • As already shown the TRV depends upon the frequency of transient which depends upon L and C. Low L and C means high frequency. And high frequency implies fast rise of TRV. 
  • The breaker when switching load/elements then the  power factor of the load or element greatly influences the shape of Transient Recovery Voltage and Recovery Voltage.
  • The breaker opening may result in independent oscillation of both sides of the breaker. Here the TRV is obtained by subtracting instantaneous voltage of one side from the voltage of other side 
  • In a three phase system the current in individual phases attain zero values one by one (120 degree phase shift between them) . If the three phase system is ungrounded then the pole that clears first (at current zero) is subjected to a recovery voltage which is 1.5 times the phase voltage. 
  • The lagging nature of fault current in alternator winding has demagnetising effect. The demagnetising effect results in reduction of emf of alternator. This results in reduction of terminal voltage. Hence the recovery voltage is less than the system voltage. 


Arcing in Circuit Breaker

Electric Arc

For interrupting power supply to a part of a network or circuit, or to clear a fault, circuit breakers are employed. On receipt of trip signal the circuit breaker operating mechanism operates to separate moving contact from the fixed contact (Fig-A). As the moving contact starts moving away from the fixed contact, the contact area of the tips of  both moving contact and fixed contact reduces. But the same current now passes through this reduced contact area. The current density of the contact area increases very much. This situation makes the areas of the tips in contact very hot, may be several thousand degrees celsius. Now as the contacts just separate these hot spots becomes source of electron emission. High energy electrons are emitted from the separated contact tips. This is called thermionic emission.

The other main cause of electron emission is field emission. As the movable contact moves away from the fixed contact voltage difference between the two electrodes (fixed and moving contacts) exist (Fig-B). Which gives rise to an electric field between the electrodes.

Electric Field = V / d

Where  V is the potential difference between the electrodes and d is the separation between the two.

So from the above formula it is clear that just after separation when the movable contact has not moved much away, then d is small so the electric field strength is very high (order of several kV per millimetre). High electric field gives rise to emission of high energy electrons from the contact surface. The high speed electrons emitted bombard the molecule or atoms of the medium and dislodge electrons from the atoms. This is secondary emission.

The high energy electrons so emitted ionise the gas or oil used as medium. Arc plasma is formed between the fixed and moving contacts. The current continues to flow through the arc plasma between the contacts (see Fig-A).

It is clear that just separating the contacts does not automatically break the circuit and flow of current does not stop. The arc is required to be extinguished. More importantly the dielectric strength of the medium between the fixed and moving contacts should be restored quickly, otherwise arc may re-strike between the contacts. This is the job of the arc interruption chamber of the circuit breaker.

Several techniques are employed for the arc extinction. The arc can be extinguished by increasing the resistance of the arc path. This is achieved by lengthening the arc or splitting the arc using one of the techniques and by reducing the diameter of the arc by cooling. By increasing the resistance the voltage drop across the arc increases. It achieves such a value that the supply voltage cannot sustain the voltage drop across the arc and the arc is extinguished.
Also in AC circuit the current varies sinusoidally so the arc is extinguished at next current zero. Although the arc is extinguished but the medium is having enough ionised particles. Hence to stop the re-striking of arc due to Transient Restriking Voltage the space between the separated contacts should rapidly regain dielectric strength. This can be done by blowing gas or air at high speed to the region between the contacts in Gas or Air Blast breaker. In case of oil circuit breaker rapid flow of oil to the contact region helps regain high dielectric strength. Regaining dielectric strength is the result of recombination of ions and electrons.

The working principles of some breakers will be discussed later.    

Circuit Breaker

In last article we discussed common bus schemes used in substations.  We felt the importance of the circuit breaker. Here we will discuss more about the circuit breakers. Although here the primary concern is about the breakers used in HV, EHV or UHV substations the basic is still applicable to low voltage breaker. Also Switchgear is a very common term often used by power system engineers. Switchgear includes circuit breaker, protective devices, and also measuring and control devices.

The main function of the circuit breaker is to break and make the circuit. So theoretically a circuit breaker is a switch. The breaker is rated so that is should be capable to make, carry and break load current during normal operation and interrupt large fault current in abnormal conditions.

Circuit breaker is the main equipment for controlling power flow and safety of other equipments and personnel. The different associated elements and basic functioning of the circuit breaker is illustrated in the simplified Figure-A. The breaker can be operated by a trained substation personnel by pressing the button at the control room. But during the fault condition it trips automatically.

When fault in the line takes place the large fault current is associated with the increase of secondary current in current transformer (CT). This will actuate the relay and relay contact closes. Now as the tripping circuit of the breaker is complete the  trip coil is energised. The energised trip coil initiates breaker mechanism for moving the circuit breaker moving contact away from fixed contact. The Arc formed between the moving contact and fixed contact is extinguished by breaker arc extinguishing mechanism. The breaker is open. From the figure it is clear that the breaker trip circuit can be closed by closing of either of the contacts C1 or C2. While C1 is for manual closing by pressing the button at the control panel, the C2 is closed automatically by breaker relay for abnormal over current condition sensed by CT. These two contacts in parallel fulfil the logic OR function. Applying same reasoning it is easy to think that the breaker can be logically conditioned for tripping on other abnormal conditions.

 The trip circuit is supplied with DC battery source. Independent AC source may be used for trip circuit. It should be noted that for high voltage breaker the fault sensing device is outside the circuit breaker where as in case of low voltage breaker the sensing device is accommodated within the breaker enclosure.

During separation of moving contact from fixed contact electric arc is produced between the contacts. Extinguishing of the arc is the most important part of breaker functioning, which greatly influences the breaker design. Actually in low and medium voltage case, the arc extinction is not of much problem. The arc extinguishing is a difficult task in HV and EHV or UHV circuit and is the primary concern for breaker design. The energy stored in the line/circuit inductance is dissipated in the arc and the arc is required to be extinguished reliably.

From the above discussion it is observed that the circuit breaker functioning is comprised of three main components.
  • Sensing and tripping circuit
  • Operating mechanism
  • Arc interruption
The breakers can be classified several ways. The most important classification is the medium used for arc interruption.

For low and medium voltage use, air is mainly used as the medium for arc extinction (In past, oil was also used for 430/220 volt system). In HV, EHV and UHV substations oil and gas is used as arc quenching medium (In the past Air Blast breakers were also often  used for HV/EHV/UHV application). Like low voltage system, Oil Circuit breakers are also becoming obsolete for higher voltage use. Vacuum is also used for arc quenching. Vacuum circuit breakers are usually used for breakers in the range of 3 kV to 38 kV.  In modern EHV and UHV substations  SF6  gas breakers have replaced the Oil circuit breakers and Air Blast circuit breakers. But one can still find Oil Breakers and Air Blast Breakers in many old substations.

SF6 is a superior gas having good dielectric strength and arc quenching ability which has proved to be a better medium for arc quenching in the breaker. An UHV SF6 Circuit Breaker is displayed below.

The circuit breakers are also available as single tank type or separate tank type. In case of separate tank type, each phase has a separate tank. For EHV application separate tank type breakers are preferred.

The circuit breakers can also be classified from the point of view of operating mechanism. The operating mechanism of the circuit breaker may be hydraulic, pneumatic or motor operated types.

The circuit breakers are also classified as live tank type or dead tank type. In case of live tank type breaker the enclosure of the breaker is at line potential. In the dead tank type breaker the enclosure of the breaker is at ground potential. The dead tank type breaker requires additional oil/gas for insulation from the grounded enclosure. Live tank type breaker requires less oil or gas.

More on Circuit Breaker is discussed in subsequent articles.

Substation Bus Schemes


We already mentioned the different types of substations. Before more in-depth discussion about each type of substation it is better to know few common essential features of a substation. Here we discuss about the bus schemes commonly implemented in an electrical substation. The Bus scheme is the arrangement of overhead bus bar and associated switching equipments in a substation. The operational flexibility and reliability of the substation greatly depends upon the bus scheme.

Here I reiterate that the electric substation is a junction point where usually more than two transmission lines terminate. Actually in most of  EHV and HV substations more than half a dozen of lines terminate. In many large transmission substations the total numbers of lines terminating exceeds one or two dozens. In this scenario obviously the first requirement is avoidance of total shutdown of the substation for the purpose  of maintenance of some equipment(s) or due to fault somewhere. Total shutdown of substation means complete shutdown of all the lines connected to this particular substation. So the switching scheme is adopted depending upon the importance of the substation, reliability requirement, flexibility and future expansion etc.. Of course substation construction and operational cost is also to be considered. Clearly a EHV or UHV transmission substation where large numbers of important lines terminate is extremely important and the substation should be designed to avoid total failure and interruption of minimum numbers of circuits.

There are mainly six bus schemes. these are:
  • Single Bus
  • Main Bus and Transfer Bus
  • Double Bus Double Breaker
  • Double Bus Single Breaker
  • Ring Bus
  • Breaker and Half
Before we proceed further I would like to discuss in brief about the Circuit Breaker and Isolator. It will be helpful for novices. See the figure below where two buses are connected by circuit breakers and isolators as shown. A circuit breaker is a device whose main purpose is to break the circuit carrying load current or fault current. As the breaker is opened then current is interrupted in the circuit. But it is not safe to work with opened breaker as one or both sides of the breaker terminals may be still energised. The breaker is then isolated from the rest of the circuit by opening the isolators on both sides of breaker. The isolators are used to isolate the breaker or circuit.  It should be remembered that the isolators are never opened or closed to interrupt or make the circuit. That means when the circuit is to be made on, first the isolators on both sides of a breaker are closed then breaker is closed to allow current flow. When the circuit is to be made off or interrupted, first the breaker is opened(tripped), hence load current is interrupted. Then to isolate the breaker, isolators are opened. Isolators are designed to interrupt small current. Breakers are designed to interrupt large load current and heavy fault current. Both breaker and isolator carry load current in normal state.

Single Bus

As the name indicate the substation with this configuration has a single bus (Fig-B). All the circuits are connected to this bus.  A fault on the bus or between the bus and a breaker results in the outage of the entire bus or substation. Failure of any breaker also results in outage of the entire bus. Maintenance of any circuit breaker requires shutdown of the corresponding circuit/line and maintenance of bus requires complete shutdown of the bus. A bypass switch across the breaker should be used for maintenance of the corresponding breaker. This case the protection system is disabled.

Single Bus configuration is the simplest and least cost of all configurations. The system can be easily expanded. This configuration requires less area. The reliability of this system being low, it is not to be implemented in the substation where high reliability is expected. Large substations usually do not utilize this scheme.  By sectionalising of the bus the reliability and availability of the single bus system can be improved.

Main Bus and Transfer Bus  

In this scheme one more bus is added. See Figure-C  how the equipments are arranged and circuits are connected between main and transfer bus. In this arrangement one more breaker may be used, known as tie circuit breaker. No circuit is associated with this tie breaker.

When the tie CB is not present, for maintenance of a circuit breaker, the transfer bus is energized by closing the isolator switches to transfer bus. Then the breaker to undergo maintenance is opened and isolated (opening isolators on both sides of CB) for maintenance. In this arrangement there is no protection for the circuits. The circuits can be protected from outside the substation.

When the tie breaker is present, for maintenance of a breaker the transfer bus is energised by closing the tie breaker. Then the isolator near the transfer bus of the breaker of circuit to be maintained is closed. Now the breaker to be maintained is opened. Then corresponding isolators on both sides of breaker are opened. The breaker is removed for maintenance.  The circuit is transferred to transfer bus. Remember that the isolator to the transfer bus corresponding to the breaker not to be maintained remain open. Here the tie breaker protects the circuit in place of removed breaker. In this scheme the relay setting is quite complex due to the requirement of the tie breaker to handle each situation for maintenance of any of the other breakers. This scheme is somewhat more costly than the single bus scheme but is more reliable. The scheme can be easily expanded. The switching procedure is complicated for maintenance of any circuit breaker. Failure of a breaker or fault on the bus results in outage of complete substation.

Double Bus Double Breaker

In this scheme there are two buses and two circuit breakers per circuit are used (See Fig-D). In normal state both the buses are energised. Any circuit breaker can be removed for maintenance without interruption of the corresponding circuit. Also the failure of one of the two buses does not interrupt any circuit as all the circuits can be fed from the remaining bus and isolating the failed bus. By shifting circuit from one bus to other the loading on the buses can be balanced.
The substation with this configuration requires twice as much equipments as single bus scheme. This scheme has high reliability. But due to more equipments this scheme is costly and requires more space. This scheme is usually used at EHV transmission substation or generating station where high reliability is required.

Double Bus Single Breaker

This scheme is shown in Fig-E. This scheme has two buses. Each circuit has one breaker and connected to both buses by isolators as shown. There is one tie breaker between two buses. The tie breaker is normally closed. For the tie breaker in closed position the circuit can be connected to either of the buses by closing the corresponding switch. It is clear that fault on one bus requires isolation of the bus and the circuits are fed from the other bus.

From the figure you can guess that the configuration has some improvement over the single bus system. This arrangement has more flexibility in operation than the single bus scheme. This scheme is costlier and requires more space than the single bus scheme. Many EHV transmission substations use this scheme with an additional transfer bus.

Ring Bus 

The Ring Bus configuration is shown in Fig-F. The breakers are so connected and forms a ring. There are isolators on both sides of each breaker. Circuits terminate between the breakers. The number of breakers is same as the numbers of circuits. Each of the circuits in ring bus system is fed from both sides. Any of the breaker can be opened and isolated for maintenance without interrupting any of the circuits. A fault on any of the circuit is isolated by tripping of two breakers on both sides of the circuit. By tripping the two breakers only the faulted circuit is isolated and all other circuits continue to operate in open ring state. This scheme has good operational flexibility and high reliability. The main disadvantage is that when a fault happens and the ring is split and may result into two isolated sections. Each of these two sections may not have the proper combination of source and load circuits. To avoid this as far as possible the source and load circuits should be connected side by side (see figure). The ring bus scheme can be expanded to accommodate more circuits. The ring bus scheme is not suitable for more than 6 circuits (although possible). When expansion of the substation is required to accommodate more circuits, the ring bus scheme can be easily expanded to One and Half Breaker(See below and compare) scheme. The scheme is required to be planned properly to avoid difficulties in future expansion.

Breaker and Half

The Breaker and Half scheme has two main buses (Fig G). Both the buses are normally energised. Three breakers are connected between the buses. The circuits are terminated between the breakers as shown. In this bus configuration for two circuits three numbers of breakers are required. Hence it is called one and half scheme.  It is something like, for controlling one circuit we require one full and a half breakers. The middle breaker is shared by both the circuits. Like the ring bus scheme here also each circuit is fed from both the buses.

Any of the breakers can be opened and removed for maintenance purposes without interrupting supply to any of the circuits. Also one of the two buses can be removed for maintenance without interruption of the service to any of the circuits. If fault happens on a bus it is isolated without interruption of supply to any of the circuits. If the middle circuit breaker fails then the breakers adjacent to the buses are tripped so interrupting both the circuits. But if a breaker adjacent to the bus fails then the tripping of middle breaker does not interrupt power supply to circuit associated with healthy breaker. Only the circuit associated with failed breaker is interrupted.

This configuration is very flexible and highly reliable. The relaying of the scheme is complicated as the middle breaker is associated with both the circuits. This scheme is economical in comparison to Double Bus Double Breaker scheme. This scheme also require more space in comparison to other schemes to accommodate more equipments.

In one substation you can find two or more schemes implemented as per the requirement. In most of the modern substations it is usual to add one transfer bus in most of the schemes above. Which enhances the availability and maintainability of the system and operational flexibility

Substation Planning and Siting

We have already discussed in brief about different types of electrical substations. Now we will discuss about the main factors influencing selection of substation. The discussion is mainly for transmission substation which requires many factors to be considered before selecting the site, size etc. The smaller or distribution substation has fewer requirements so only some of the points are required to be considered.

A substation is like a junction point in a power system. Many transmission lines at different voltage levels terminate at a substation. Shut down of the substation means shutdown of all the lines terminating at the substation. Clearly a substation is a very important unit of power system.

A transmission substation may be comprised of  one or more of the following main sections depending on its size and importance. These are Switchyards, Control rooms, Office building and Colony for employees. See the figure at the bottom. The substation planning requires several factors to be considered. A substation which is not properly planned or Ill designed may face several problems, in particular if future expansion or renovation of the switchyard is required. Proper design of substation also enables it to operate in normal state for maximum possible time so avoiding overloading to the maximum. It is true that many substations undergo expansion and renovation with time. So for substation planning future expansion must be considered.

There are several factors that need to be considered for deciding for a substation. Some of these requirements are actually the purpose of the substation while the others are the requirements to fulfill the purpose.

Some important primary factors in the design of substation are operational flexibility, supply reliability, secutity and short circuit withstand capability etc.

One important factor to be considered first is the site selection. Substation design and some equipment selection depends on site selection. Hence it has a bigger influence on the cost of substation. The orientation of the lines to be terminated at the substation also decides the substation orientation and equipment arrangement.

The site should be near the load center keeping in view the future load growth.

Some general factors to be considered are listed. It should be remembered that some of the factors are actually interdependent.
  • Access road to the site for smooth movement of construction machines, equipments and transformers. Good Roadways to construction site and shorter distance to rail head are desired.
  • The site should be chosen to avoid soil filling, earth removal etc. The requirement of soil filling and earth removal takes time and increases total cost of substation 
  • Historical data of worst flood is taken into account to avoid water logging of the substation in case of possibility of flood. Flood plains and wetlands are avoided. 
  • Atmospheric conditions like salt and suspended chemical contaminants influence selection of equipments and maintenance requirements. 
  • Interference with communication signals. The construction company have to take permission from the appropriate authority.
  • Electric and magnetic field strength are of particular concern especially for Ultra High Voltage (UHV) systems at 765 kV,1200 kV or above. Research organisations has shown the impact of strong Electric/magnetic fields due to UHV substations and lines on human health. Such new concerns are also required to be addressed properly 
  • Forest land, sanctuaries and national parks are avoided. Almost all governments has laid stringent rules to comply for approval of forest land and wild life sanctuary. The usual process takes time to get approval from the concerned authorities. This process delays the construction activities.
  • Approval is also required from aviation authority. Substation should be away from airport and defence establishments. 
  • Water supply and sewage system are the two most important facilities to be given due consideration.
Some other factors related to the general public:
  • The substation should be located far from the crowded places. Efforts are always made to locate transmission substations outside the city areas.
  • The locals should be made aware of the upcoming substation. To avoid public resentment it is better to involve the local people in the process. If required they should be educated and trained. Many times the local people also plays an important role to check vandalism and theft.
  • Heritage sites and tourist spots are avoided.
  • Electric substation is a source of noise. While charged transformers, reactors and EHV lines are sources of continuous hissing noise, operation of different equipment  also emit sudden noise. The design should be adopted to tackle the issues by complying to the standards set by the appropriate authority for reduction of noise pollution and avoid public resentments.   
  • Landscaping should be done to keep the substation out of direct view of common people. 

Finally it is safety of man and machine. The safety of the personnel involved both in construction phase, operational safety and safety of public is to be followed as per the safety rules and regulations framed by international bodies and local authorities. These rules are not to be compromised. Moreover the manufacturer  instruction manuals,  safety procedures and other documents for equipment and machines are to be referred.

A substation should have adequate arrangement of fire fighting system. It is the ultimate safety measure of any substation. The fire fighting system should be suitable for dealing with fire due to electrical arc. Usually costly equipments like transformer should have Nitrogen gas or high speed water jet as fire fighting system.

In the figure below is a conceptual substation

The substation has 400 kV, 220 kV and 33 kV switchyards. Here some of the equipments/parts are identified. There are two 400/220 kV, 315 MVA Inter Connecting Transformers (ICT). One 220/33 kV, 100 MVA step down transformer is used for feeding the distribution network. The double arrow-head lines represent control and data channels between switchyard equipments and control room.

Long Transmission Line

In the last article we discussed short and medium length lines. Now is the time for long transmission lines. For long transmission lines if we apply the formula for medium length line we will get large error. The error becomes larger with longer transmission lines and the method is useless.  So for long lines it becomes important to represent accurately. Hence the long transmission lines are represented by distributed parameters.

Long Line Model

For medium length line we lumped the line impedance at one place. This line impedance which is actually distributed throughout the length of line will be represented here as distributed.  The capacitive current between the line conductors flows throughout the length of line. Which necessitates for distributing the line to line capacitance throughout the length of the line.  But for a balanced three phase system we  analyse per phase analysis. Which necessitates for consideration of phase to neutral capacitance, Both line inductance and capacitance for several configurations are illustrated in previous articles. The equivalent long line representation is shown in Fig-A.

In the diagram the distributed capacitance also automatically requires that the line impedance also distributed. It should be clear from the above figure that in general throughout the length of the line the voltage and current values may vary.

What is the voltage and current at a distance x from the receiving end. See Fig-B Let the voltage and current at a distance x from receiving end are V(x) and I(x) respectively. It should be noted that V(x) and I(x) are phasors.

Let  Z= √(Z/Y)
and   γ =√(ZY)

As Z and Y are complex numbers so in general Z and γ are complex numbers. Z is called the characteristics impedance and γ is the propagation constant. Z is commonly called surge impedance in power sector.

Formula for calculation of Z and Y are already discussed in previous articles.
Z is the series impedance per unit length ( impedance per kilometer or meter)
Y is the shunt Admittance per unit length

Using differential calculus and solving the resulting differential equations it can be shown that,

The above formula can be rearranged and written in several ways. Rearranging the terms and using the formulas of complex hyperbolic, the above formulas for V(x) and I(x) can be written in the form

To find the voltage Vs and current Is at the sending end, we just have to put l (length of line) in place of x  in the above formulas. So at the sending end

If you compare the above equations relating sending and receiving end voltage and current with the corresponding equations discussed in last article for medium length lines then we can easily find ABCD parameters. These are

You can argue that the long transmission line can also be represented by a nominal  ∏ circuit. Yes a long line can be represented by an equivalent ∏ circuit. It should be remembered that in case of medium length line it is called Nominal ∏. Here it is called equivalent  ∏. This equivalent ∏ is only a convient representation of the actual long line analysis. But Nominal ∏ is an approximation for medium lines. For load flow study and other system studies this equivalent representation is very helpful without sacrificing any accuracy. In Fig-C is shown the equivalent ∏ representation of any line of length l according to long line theory.

It is left as an exercise for you to find Z' and Y' by comparing with Medium length line.

Surge Impedance loading

In all the above formulas we used two parameters Zand  γ. These two parameters are very important. Of course these two parameters are derived from our transmission line parameters Z and Y. The characteristics of the long line depends upon these two  parameters.

As already said Zc  and γ  are complex numbers.

Let us consider a case when the load impedance is just equal to the characteristics impedance Zc   then, the receiving end voltage  Vr  =IZc   

substituting in above equations we get


let, γ  = α+j β

Dividing V(x) by I(x) we get

From the above equation it is easy to interpret that the impedance as seen at any point of the line is the same as the load impedance that is Z, the characteristics impedance. Moreover from the above equations of  V(x) and I(x) it is clear that

The magnitude of voltage is 

Clearly the magnitude of the voltage increases with x. But our x increases from receiving end to sending end. So the voltage increases exponentially from receiving end to sending end.

At the sending end the voltage is

The other term   is the phasor and only provides phase shift between the voltages at receiving end and at a point x distance from the receiving end. Similar argument can be made for equation of current I(x).

In the above formula of Zc and γ  we put Z(series impedance) and Y(shunt admittance). (recall that Z and Y are the values per unit line length)

Loss Less Line

What will happen for a loss less line. For loss less line R=0 and G=0.
So our above equations reduces to

Observe that for loss less line, Zc becomes a pure resistance. We also know that γ  = α+j β,  for this loss less situation we get

Now our previous voltage and current equations for surge impedance loading reduces to

As in case of lossy line here also at any distance x from receiving end the ratio of voltage and current is always same that is Zc, the surge impedance of the line. Using the complex algebra you are sure that the magnitude of V(x) is Vr and I(x) is Ir. Which means that for loss less line the voltage and current at any distance x from the receiving end is same. It also implies voltage at sending end is same as voltage at receiving end which is same as voltage at any intermediate point. So Vs = V(x) = Vr. At Surge Impedance Loading the reactive power generated by the line capacitance is equal to the reactive power absorbed by the line inductance for every unit length of line. In Power industry it is said that the voltage profile is flat. So we conclude that for a lossless line the voltage magnitude is same throughout the length of line. As in case of lossy line the term  is the phasor responsible for phase shift. It is simply giving phase shift to the voltage wave along the length of line. The phase angle between sending and receiving end voltage is  . It is clear that if the distance between the sending and receiving end is more then the phase difference between the voltage phasors at both the ends of the line will be more.  

In previous articles we already discussed that in case of transmission line how and when we can ignore the line resistance R and  leakage  conductance G. At least for rough estimate of the load carrying capability of transmission line we can presume it lossless. The surge impedance loading is the ideal loading of the line, which is desired keeping in view of the optimised (flat for lossless ideal case) voltage profile of the line. 

For Loss less line the surge impedance loading (SIL) is


It should be recalled that Zc is pure resistance for lossless line.

Vr and Vl are the receiving end phase and line voltage respectively.

Approximate SIL for few nominal voltages  
  • 132/138 kV  -    50 MW
  • 230 kV         -  150 MW
  • 345 kV         -  400 MW
  • 400 kV         -  500 MW
  • 500 kV         -  900 MW
  • 765 kV         -  2090 MW

Above values of SIL is true for both 50 Hz and 60 Hz systems.

Line Loadability

System planners usually use line loadabilty curve for deciding loading capability of the line. See Fig-D. The relationship between SIL and length in km shown in Fig-D is almost same for all voltage levels.

What is the capacity of the transmission line or how much power it can carry. The power that a transmission line can carry are based on three factors. These are
  • Thermal Limit
  • Voltage Drop Limit
  • Stability Limit
Due to the current flow heat is generated in the line and the line length changes which gives rise to more sag.  Sometimes heating of the line is enough that, later cooling of the line due to less load or environment factors does not make the line regain its actual length. The sagging become permanent. Due to this the minimum clearance of the line to ground decreases which may violates the standard set by the local authority. Also if the load is very high the conductor may be damaged due to excessive heat. All transmission lines has thermal limits. But the thing is that only short lines can approach this limit. Voltage drop and stability limits situation usually do not arise here due to short length. Lines less than 80 km length falls in this category.

For medium length line the loading is mainly limited by allowable voltage drop (usually between 5 to 10 % as set in grid standard). For medium length line the steady state stability limit situation usually does not arises due to lesser length(discussed below). But the length is enough so that the medium length line can encounter the voltage drop limit before reaching thermal limit. By reactive compensation the voltage drop limit can be increased. Lines exceeding 80 km and less than 250 km long belong to this category.

For long line(above 250 km) we have shown that effort is made to operate the line with surge impedance loading.  So for long lines the voltage profile may be made more or less flat with SIL loading. If the loading of line exceeds above SIL then  the voltage at receiving end is less than sending end. If the loading of the line is less than SIL then the voltage at receiving end is more than sending end. This phenomenon is called Ferranti effect. For very lightly loaded or open long lines the voltage at receiving end may become very high. To avoid this situation Reactors are used at receiving end.

In both lossy and lossless lines it is clear that phase difference between sending and receiving end voltage arises. This angle is called power angle. The power that flows from sending to receiving end depends upon this angle and the magnitude of Vs and Vr. (The magnitude of a phasor V is represented as |V| )

The simplified formula for this power (P) transmitted is

X is the equivalent series reactance(ignoring resistance) of the line.

To increase the power to be transmitted, this power angle δ may increase up to 90 degrees. Increasing slightly further, the line becomes unstable and lose synchronism. It is a good practice to operate the lines with sending and receiving ends phase differnce angle (power angle) less than 30 degrees.  Doing so, if in emergency load generation disbalance in adjacent areas occurse this line can take more load by increasing this power angle, so avoiding instability. So operating below 30 degrees we keep more than 60 degree angle margin. From the above formula you can say that if X is made smaller and smaller for any fixed small δ ( small sin δ  imply small δ)  then more power can be transmitted. Hence it is clear that small line reactance X is desired. This small reactance which cannot be made arbitrarily small by line design, definitely limit the power transmission in line.  This loading limit for transmission line is quite less than thermal limit.  So the long lines cannot approach thermal limit, before that other limits come to action. This small power angle corresponds to quite lesser load carrying capacity in comparison to thermal limit. Effort is made by power companies to push the limit towards thermal limit by employing reactive compensation so reducing effective series X further.