HDCT-4

High Voltage Direct Current(HVDC)

Introduction

A high-voltage direct current (HVDC) electric power transmission system uses direct

current for the bulk transmission of electrical power, in contrast with the more

common alternating current systems. For long-distance distribution, HVDC systems are less

expensive and suffer lower electrical losses. For shorter distances, the higher cost of DC

conversion equipment compared to an AC system may be warranted where other benefits of

direct current links are useful.

The modern form of HVDC transmission uses technology developed extensively in the 1930s

in Sweden at ASEA. Early commercial installations included one in the Soviet Union in 1951

between Moscow and Kashira, and a 10-20 MW system in Gotland, Sweden in 1954.

High Voltage Transmission

High voltage is used for transmission to reduce the energy lost in the resistance of the wires. For

a given quantity of power transmitted, higher voltage reduces the transmission power loss.

Power in a circuit is proportional to the current, but the power lost as heat in the wires is

proportional to the square of the current. However, power is also proportional to voltage, so for

a given power level, higher voltage can be traded off for lower current. Thus, the higher the

voltage, the lower the power loss. Power loss can also be reduced by reducing resistance,

commonly achieved by increasing the diameter of the conductor; but larger conductors are

heavier and more expensive.

High voltages cannot be easily used in lighting and motors, and so transmission-level voltage

must be reduced to values compatible with end-use equipment. The transformer, which only

works with alternating current, is an efficient way to change voltages. Practical manipulation of

DC voltages only became possible with the development of high power electronic devices such

as mercury arc valves and later semiconductor devices, such as thyristors, insulated-gate bipolar

transistors (IGBTs), high power capable MOSFETs (power metal–oxide–semiconductor field-

effect transistors) and gate turn-off thyristors (GTOs)

www.eeecube.blogspot.com



Advantages and Limitations of alternating current transmission

The advantage of HVDC is the ability to transmit large amounts of power over long distances

with lower capital costs and with lower losses than AC. Depending on voltage level and

construction details, losses are quoted as about 3% per 1,000 km. High-voltage direct current

transmission allows efficient use of energy sources remote from load centers.

In a number of applications HVDC is more effective than AC transmission. Examples include:

Undersea cables, where high capacitance causes additional AC losses.

Endpoint-to-endpoint long-haul bulk power transmission without intermediate 'taps', for

example, in remote areas

Increasing the capacity of an existing power grid in situations where additional wires are

difficult or expensive to install

Power transmission and stabilization between unsynchronised AC distribution systems

Connecting a remote generating plant to the distribution grid

Stabilizing a predominantly AC power-grid, without increasing prospective short circuit

current

Reducing line cost. HVDC needs fewer conductors as there is no need to support multiple

phases. Also, thinner conductors can be used since HVDC does not suffer from the skin

effect

Facilitate power transmission between different countries that use AC at differing

voltages and/or frequencies

Synchronize AC produced by renewable energy sources

Long undersea cables have a high capacitance. While this has minimal effect for DC

transmission, the current required to charge and discharge the capacitance of the cable causes

additional I2R power losses when the cable is carrying AC. In addition, AC power is lost

to dielectric losses.

HVDC can carry more power per conductor, because for a given power rating the constant

voltage in a DC line is lower than the peak voltage in an AC line. In AC power, the root mean

square (RMS) voltage measurement is considered the standard, but RMS is only about 71% of

the peak voltage. The peak voltage of AC determines the actual insulation thickness and

conductor spacing. Because DC operates at a constant maximum voltage without RMS, this




allows existing transmission line corridors with equally sized conductors and insulation to carry

29% more power into an area of high power consumption than AC, which can lower costs.

Because HVDC allows power transmission between unsynchronised AC distribution systems, it

can help increase system stability, by preventing cascading failure from propagating from one

part of a wider power transmission grid to another. Changes in load that would cause portions

of an AC network to become unsynchronized and separate would not similarly affect a DC link,

and the power flow through the DC link would tend to stabilize the AC network. The magnitude

and direction of power flow through a DC link can be directly commanded, and changed as

needed to support the AC networks at either end of the DC link. This has caused many power

system operators to contemplate wider use of HVDC technology for its stability benefits alone

Disadvantages

The disadvantages of HVDC are in conversion, switching and control. Further operating an

HVDC scheme requires keeping many spare parts, which may be used exclusively in one

system as HVDC systems are less standardized than AC systems and the used technology

changes fast.

The required static inverter are expensive and have limited overload capacity. At smaller

transmission distances the losses in the static inverters may be bigger than in an AC

transmission line. The cost of the inverters may not be offset by reductions in line construction

cost and lower line loss.

In contrast to AC systems, realizing multiterminal systems is complex, as is expanding existing

schemes to multiterminal systems. Controlling power flow in a multiterminal DC system

requires good communication between all the terminals; power flow must be actively regulated

by the control system instead of by the inherent properties of the transmission line. High

voltage DC circuit breakers are difficult to build because some mechanism must be included in

the circuit breaker to force current to zero, otherwise arcing and contact wear would be too great

to allow reliable switching. Multi-terminal lines are rare




Costs of high voltage DC transmission

Normally manufacturers such as AREVA, Siemens and ABB do not state specific cost

information of a particular project since this is a commercial matter between the manufacturer

and the client.

Costs vary widely depending on the specifics of the project such as power rating, circuit length,

overhead vs. underwater route, land costs, and AC network improvements required at either

terminal. A detailed evaluation of DC vs. AC cost may be required where there is no clear

technical advantage to DC alone and only economics drives the selection.

Rectifying and inverting

Components

Early static systems used mercury arc rectifiers, which were unreliable. The thyristor valve was

first used in HVDC systems in the 1960s. The thyristor is a solid-state semiconductor device

similar to the diode, but with an extra control terminal that is used to switch the device on at a

particular instant during the AC cycle. The insulated-gate bipolar transistor(IGBT) is now also

used and offers simpler control and reduced valve cost.

Because the voltages in HVDC systems, up to 800 kV in some cases, exceed the breakdown

voltages of the semiconductor devices, HVDC converters are built using large numbers of

semiconductors in series. Though 800kV systems are still to be realised in India.

The low-voltage control circuits used to switch the thyristors on and off need to be isolated

from the high voltages present on the transmission lines. This is usually done optically. In a

hybrid control system, the low-voltage control electronics sends light pulses along optical fibres

to the high-side control electronics. Another system, called direct light triggering, dispenses

with the high-side electronics, instead using light pulses from the control electronics to switch

light-triggered thyristors (LTTs).




Rectifying and inverting system

Rectification and inversion use essentially the same machinery. Many substations are set up in

such a way that they can act as both rectifiers and inverters. At the AC end a set of transformers,

often three physically separate single-phase transformers, isolate the station from the AC

supply, to provide a local earth, and to ensure the correct eventual DC voltage. The output of

these transformers is then connected to a bridge rectifier formed by a number of valves. The

basic configuration uses six valves, connecting each of the three phases to each of the two DC

rails. However, with a phase change only every sixty degrees, considerable harmonics remain

on the DC rails.

An enhancement of this configuration uses 12 valves (often known as a twelve-pulse system).

The AC is split into two separate three phase supplies before transformation. One of the sets of

supplies is then configured to have a star (wye) secondary, the other a delta secondary,

establishing a thirty degree phase difference between the two sets of three phases. With twelve

valves connecting each of the two sets of three phases to the two DC rails, there is a phase

change every 30 degrees, and harmonics are considerably reduced.

In addition to the conversion transformers and valve-sets, various passive resistive and reactive

components help filter harmonics out of the DC rails.

The theory of the HVDC converter

The considerations are restricted on the line commutated converter which so far has dominantly

been used for HVDC systems. Although forced commutated converters have occasionally been

proposed for very special applications such as tapping of an HVDC line, the thyristor based

converter is still the only economical and well proven solution for bulk power transmission.

The Three-pulse Commutation group

Of the numerous converter configurations which have come into use for a wide variety of

applications, HVDC technology uses exclusively the three phase bridge circuit. In many

respects this is optimal converter connection. The three-phase bridge consists of two three-pulse

commutation groups connected in series. The star point loading is of no consequence, since it

disappears when the circuit is expanded into the six pulse bridge. The starpoint loading has been

taken into account by means of delta connection on the primary side. A symmetrical ac network

with no impedance and with no impedance and with sinusoidal voltage UL is assumed, as is

generally customary in converter theory. In addition, a completely smooth direct current (Id)

effected by a smoothing reactor with infinite inductance (ld) is also assumed.




The Commutation process

In actuality, commutation of direct current requires a certain amount of time. This is due to

leakage inductances of the converter transformer, which only permit a current change of limited

steepness. Thus for a short period of time, the releasing and the receiving phases are carrying

current simultaneously. This is referred to as commutation overlap and its duration is defined as

the overlap angle U. The leakage inductances are considered lumped elements on the valve side

of the transformer.

Assume that valve 1 carries the direct current and that at an arbitrary point in time (after the

voltage intersection) valve 3 receives a control impulse. A current loop will be created with Uv

as the driving voltage. The leakage inductances of phases 1 and 3 will be the reactances which

determine the current. This is simply a phase to phase short circuit of the transformer. The short

circuit current flows through valve 3 in the forward direction and through valve 1 counter to the

forward direct current. As soon as the short circuit current has achieved the amplitude of the

direct current (the composite current is zero), valve 1 extinguishes. At this point, the

commutation process has ended and valve 3 is carrying the entire direct current. Curve of the

direct voltage during commutation is along the average value of the voltages of valves 1 and 3.

Basic HVDC converter control concepts

The converter valves, as precise and virtually delay-free control elements, are the most

important actuators of the HVDC control system. Moreover, in most cases the converter groups

have an additional actuator in the form of the transformer tap changer. Although it does not

operate on a continuous basis and there are relatively long periods of idle time, it nevertheless is

responsible for important control function.

Current control

Current control mainly determines

Steady state transmission power

Changes in transmission power according to size and rate of change

The dynamic behavior of the system including temporary overload

Limitation of transient overcurrents determined by amplitude and duration




The loading of all essential components of an HVDC system, with the exception of filter

circuits, is determined by the direct current or an alternating current proportional to the

direct current. Therefore current control is also a very essential protective function.

In HVDC two point systems, the rectifier generally assumes the task of the current control. It

is occasionally advantageous to assign the current control function to the inverter. However,

since the current control of the rectifier is needed as a proactive function, it is advantageous

to also use it for this purpose during normal operation. Then it is always active and monitors

itself.

Configurations

Monopole and earth return

In a common configuration, called monopole, one of the terminals of the rectifier is connected

to earth ground. The other terminal, at a potential high above, or below, ground, is connected to

a transmission line. The earthed terminal may or may not be connected to the corresponding

connection at the inverting station by means of a second conductor.

If no metallic conductor is installed, current flows in the earth between the earth electrodes at

the two stations. Therefore it is a type of single wire earth return. The issues surrounding earth-

return current include

Electrochemical corrosion of long buried metal objects such as pipelines

Underwater earth-return electrodes in seawater may produce chlorine or otherwise affect

water chemistry.

An unbalanced current path may result in a net magnetic field, which can affect magnetic

navigational compasses for ships passing over an underwater cable.

These effects can be eliminated with installation of a metallic return conductor between the two

ends of the monopolar transmission line. Since one terminal of the converters is connected to

earth, the return conductor need not be insulated for the full transmission voltage which makes

it less costly than the high-voltage conductor.




BIPOLAR

In bipolar transmission a pair of conductors is used, each at a high potential with respect to

ground, in opposite polarity. Since these conductors must be insulated for the full voltage,

transmission line cost is higher than a monopole with a return conductor. However, there are a

number of advantages to bipolar transmission which can make it the attractive option.

Under normal load, negligible earth-current flows, as in the case of monopolar

transmission with a metallic earth-return. This reduces earth return loss and environmental

effects.

When a fault develops in a line, with earth return electrodes installed at each end of the

line, approximately half the rated power can continue to flow using the earth as a return path,

operating in monopolar mode.

Since for a given total power rating each conductor of a bipolar line carries only half the

current of monopolar lines, the cost of the second conductor is reduced compared to a

monopolar line of the same rating.

In very adverse terrain, the second conductor may be carried on an independent set of

transmission towers, so that some power may continue to be transmitted even if one line is

damaged.

A bipolar system may also be installed with a metallic earth return conductor.

Bipolar systems may carry as much as 3,200 MW at voltages of +/-600 kV. Submarine cable

installations initially commissioned as a monopole may be upgraded with additional cables and

operated as a Bipole.

Corona Discharge

Corona discharge is the creation of ions in a fluid (such as air) by the presence of a

strong electric field. Electrons are torn from neutral air, and either the positive ions or else the

electrons are attracted to the conductor, while the charged particles drift. This effect can cause

considerable power loss, create audible and radio-frequency interference, generate toxic

compounds such as oxides of nitrogen and ozone, and bring forth arcing.

Both AC and DC transmission lines can generate coronas, in the former case in the form of

oscillating particles, in the latter a constant wind. Due to the space charge formed around the

conductors, an HVDC system may have about half the loss per unit length of a high voltage AC

system carrying the same amount of power. With monopolar transmission the choice of polarity




of the energised conductor leads to a degree of control over the corona discharge. In particular,

the polarity of the ions emitted can be controlled, which may have an environmental impact

on particulate condensation. (Particles of different polarities have a different mean-free

path.) Negative coronas generate considerably more ozone than positive coronas, and generate

it further downwind of the power line, creating the potential for health effects. The use of

a positive voltage will reduce the ozone impacts of monopole HVDC power lines.

Applications

Overview

The controllability of current-flow through HVDC rectifiers and inverters, their application in

connecting unsynchronized networks, and their applications in efficient submarine cables mean

that HVDC cables are often used at national boundaries for the exchange of power. Offshore

windfarms also require undersea cables, and their turbines are unsynchronized.

AC network interconnections

AC transmission lines can only interconnect synchronized AC networks that oscillate at the

same frequency and in phase. Many areas that wish to share power have unsynchronized

networks. However, HVDC systems make it possible to interconnect unsynchronized AC

networks, and also add the possibility of controlling AC voltage and reactive power flow.

A generator connected to a long AC transmission line may become unstable and fall out of

synchronization with a distant AC power system. An HVDC transmission link may make it

economically feasible to use remote generation sites. Wind farms located off-shore may use

HVDC systems to collect power from multiple unsynchronized generators for transmission to

the shore by an underwater cable.

In general, however, an HVDC power line will interconnect two AC regions of the power-

distribution grid. Machinery to convert between AC and DC power adds a considerable cost in

power transmission. The conversion from AC to DC is known as rectification and from DC to

AC as inversion. Above a certain break-even distance (about 50 km for submarine cables, and

perhaps 600–800 km for overhead cables), the lower cost of the HVDC electrical conductors

outweighs the cost of the electronics.




Transmission Planning Criteria Introduction

The objective of system planning is to evolve a power system with a level of performance

characterised by an acceptable degree of adequacy and security based on a trade-off between

costs and risks involved. Insofar as power transmission systems are concerned , there are no

widely adopted uniform guidelines which determine the criteria for transmission planning vis-s-

vis acceptable degree of adequacy and security. The criteria generally depends on the factors

such as availability of generation vis-à-vis demand, voltage levels, and configuration of the

system, control and communication facilities and resource constraints. Practices in this regard

vary from country to country. The common theme in the various approaches is the “acceptable

system performance”. Even though the factors affecting system performance are probabilistic in

nature, deterministic approach has been used most commonly, being rather easy to apply. For

adopting probabilistic approach, long operating experience and availability of reliable statistical

data regarding performance of system components, namely equipment failure rate, outage

duration, etc, are essential. Such data are presently being compiled by a few utilities; but these

are still inadequate to go in for a totally probabilistic approach. Hence it is considered prudent

to adopt a deterministic approach for the present with a committed thrust towards progressive

adoption of probabilistic approach.

Planning Philosophy

The transmission system shall be planned on the basis of regional self-sufficiency with an

ultimate objective of evolving a National Power Grid. The regional self-sufficiency

criteria based on load generation balance may still dictate to have inter-regional

exchanges with adequate inter-connection capacity at appropriate points taking into

account the topology of the two networks, the plant mix consideration, generation

shortages due to forced outages, diversity in weather pattern and load forecasting errors

in either regions. Such inter-regional power exchanges shall also be considered these

studies.

The system shall be evolved based on detailed power system studies which shall include:-

1. Power Flow Studies

2. Short Circuit Studies

3. Stability Studies

4. EMTP Studies to determine switching/temporary overvoltages .




The adequacy of the transmission should be rested for different feasible load generation

scenarios.

The following options may be considered for strengthening of the transmission network:-

1. Addition of new Transmission lines to avoid overloading of existing

system.(Whenever three or more circuits of the same voltage class are envisaged

between two sub-stations, the next transmission voltage should also be considered.)

2. Application of Series Capacitors in existing transmission line to increase power

transfer capability.

3. Upgradation of the existing AC transmission lines.

4. Reconductoring of the existing AC transmission line with higher size conductors or

with AAAC.

5. Adoption of multi-voltage level and multi-circuit transmission lines.

The choice shall be based on cost, reliability, right-of-way requirements, energy losses,

down time (in case of upgradation and reconductoring options)

In case of generating station close to a major load centre, sensitivity of its complete

closure with loads to be met(to the extent possible)from other generating stations is also

studied.

In case of transmission system associated with Nuclear Power Stations there shall be two

independent sources of power supply for the purpose of providing start-up power

facilities. Further the angle between start-up power source and the NPP switchyard

should be, as far as possible, maintained within 10 degrees.

The evacuation system for sensitive power stations viz., Nuclear power stations shall

generally be planned so as to terminate it at large load centres to facilitate islanding of the

power station in case of contingency.

Contingency is the temporary removal of one or more system elements from service. The

cause or reason for such removal may be a fault , planned maintenance/repair etc.

1. Single Contingency – The contingency arising out of removal of one system element

from service.

2. Double Contingency – The contingency arising out of removal of two system elements

from service. It includes a D/C line, two S/C lines in same corridor or different corridors,

a S/C line and a transformer etc.

3. Rare Contingency – Temporary removal of complete generating station or complete sub-

station (including all the incoming & outgoing feeders and transformers ) from service,

HVDC bipole and stuck breaker condition.




Where only two circuits are planned for evacuation of power from a generating station,

these should be two single lines instead of a double circuit line.

Reactive power flow through ICTs shall be minimal. Normally it shall not exceed 10% of

the rating of the ICTs. Whenever voltage on HV side of ICT is less than 0.975 pu, no

reactive power shall flow through ICT.

Thermal/Nuclear Generating units shall normally not run at leading power factor.

However, for the purpose of charging, generating unit may be allowed to operate at

leading power factor as per the respective capability curve.

Inter-regional links shall, in the present context, be planned as asynchronous ties unless

otherwise permitted from operational consideration.

Load Generation Scenarios

The load-generation scenarios shall be worked out so as to reflect in a pragmatic manner the

daily and seasonal variations in the load demand and generation availability.

Load demands

The profile of annual and daily demands will be determined from past data. These data will

usually give the demand at grid supply points and for the whole system identifying the

annual and daily peak demand.

Active power

The system peak demands shall be based on the latest reports of Electric Power Survey

(EPS) Committee. In case these peak load figures are more than the peaking availability, the

loads will be suitably adjusted substation wise to match with the availability.

The load demands at other periods (seasonal variations and minimum loads)shall be derived

based on the annual peak demand and past pattern of load variations.

From practical considerations the load variations over the year shall be considered as under:-

1. Annual Peak Load – It is the simultaneous maximum demand of the system being

studied. It is based on latest Electric Power Survey (EPS) or total peaking power

availability, whichever is less.

2. Seasonal variation in Peak loads(corresponding to high thermal and high hydro

generation)




3. Minimal load – It is the expected minimum system demand and is determined from

average ration of annual peak load and minimum load observed in the system for the last

5 years.

4. Off-Peak Load relevant where Pumped Storage Plants are involved or inter-regional

exchanges are envisaged.

Reactive Power (MVAR)

Reactive Power plays an important role in EHV transmission system planning and hence

forecast of reactive power demand on an area-wise or substation-wise basis is as important

as active power forecast. This forecast would obviously require adequate data on the reactive

power demands at different substations as well as the projected plans for reactive power

compensation.

For developing an optimal power system, the utilities must clearly spell out the substation-

wise maximum and minimum demand in MWs and MVARs on seasonal basis. This will

require compilation of past data in order to arrive at reasonably accurate load forecast.

Recognising the fact that this data is presently not available, it is suggested that pending

availability of such data, the load power factor at 120/132KV voltage levels shall be taken as

0.85 lag during peak load condition and 0.9 lag during light load condition expecting areas

feeding predominantly agricultural loads where power factor can be taken as 0.75 and 0.85

for peak load and light load conditions respectively. In areas where power factor is less than

the limit specified above, it shall be the responsibility of the respective utility to bring the

load power factor to these limits by providing shunt capacitors at appropriate places in the

system.

Generation Despatches

Generation despatch of Hydro and Thermal/Nuclear units would be determined judiciously on

the basis of hydrology as well as scheduled maintenance program of the generating stations.

Various norms are used for working out the peaking availability of different types of generating

units. In case of nuclear units the minimum level of output shall be taken as not less than 70%

of the rated capacity.




Generation dispatches corresponding to the following operating conditions shall be considered

depending on the nature and characteristics of the system.

Annual Peak Load

Maximum Thermal generation – It is the condition when hydro generation is low(not

necessarily minimum)and thermal generation is kept maximum to meet seasonal peak

loads(not necessarily annual peak load).In other words it is the condition when the gap

between monthly peak demand and hydro power availability is maximum.

Maximum Hydro generation – It is the condition when hydro power availability is

maximum during the year. It is also known as High Hydro condition.

Annual Minimum Load

Special area dispatches – It is the condition when power output from all the generating

stations located in an area (in close proximity) is kept at the maximum feasible level.

Maximum Feasible level of a generating station is the maximum power output when all

the units in a power station are in service, assuming no planned or forced outages.

However, in case of power station/complex where six or more units exist, for every six

units one unit –second largest-is assumed to be under annual planned maintenance.

Special dispatches corresponding to high agricultural load with low power factor,

wherever applicable.

Off peak conditions with maximum pumping load where Pumped Storage stations exist

and also with the inter-regional exchanges, if envisaged.

Complete closure of a generating station close to a major load centre.

The generation dispatch for purpose of carrying out sensitivity studies corresponding to

complete closure of generating station close to a major load centre shall be worked out by

increasing generation at other stations to the extent possible keeping in view the

maximum likely availability at these stations, ownership pattern, shares etc.

Permissible Line Loading Limits

Permissible line loading limit depend on many factors such as voltage regulation,

stability and thermal capacity etc. Thermal capacity of a line refers to the amount of

current that can be carried by a line conductor without exceeding its design operating

temperature.

Surge Impedance Loading (SIL) means a unit power factor load over a resistance line

such that series reactive loss (I^2*R) along the line is equal to shunt capacitive gain

(V^2*Y). Under these conditions the sending end and receiving end voltages and current




are equal in magnitude but different in phase position. While SIL gives a general idea of

the loading capability of the line , it is usual to load the short lines above SIL and long

lines lower than SIL (because of the stability limitations).line loading can also be shown

(in terms of surge impedance loading of uncompensated line)as a function of line length

assuming a voltage regulation of 5% and phase angular difference of 30 degrees between

the two ends of the line. In case of shunt compensated lines, the SIL will get reduced by a

factor k, where

k = sqrt (1-degree of compensation)

For lines whose permissible line loading as determined from the curve is higher than the

thermal loading limit, permissible loading limit shall be restricted to thermal loading

limit.

Thermal loading limits are generally decided by design practice on the basis of ambient

temperature, maximum permissible conductor temperature, wind velocity, etc. In India,

the ambient temperatures obtaining in the various parts of the country are different and

vary considerably during the various seasons of the year. Designs of transmission line

with ASCR conductors in EHV systems will normally be based on a conductor

temperature limit of 75 deg Celsius. However, for some of the existing lines which have

been designed for a conductor temperature of 65 deg Celsius the loading shall be

correspondingly reduced. In the case of AAAC conductors, maximum conductor

temperature limit will be taken as 85 deg Celsius.

Temporary Overvoltages

These are power frequency overvoltages produced in a power system due to sudden load

rejection, single-phase-to-ground faults etc.

420 kV system 1.5 p.u. peak phase to neutral (343 kV = 1 p.u.)


Switching Overvoltages

These overvoltages generated during switching of lines, transformers and reactors etc. having

wave fronts 250/2500 micro sec.






Reactive Power Compensation

Shunt Capacitors

Reactive Compensation should be provided as far as possible in the low voltage systems

with a view to meeting the reactive power requirements of load close to the load points

thereby avoiding the need for VAR transfer from the high voltage system to the low

voltage system. In the cases where network below 132/220 kV voltage level is not

represented in the system planning studies, the shunt capacitors required for meeting the

reactive power requirements of load shall be provided at 132/220 kV buses.

Shunt Reactors

Switchable reactors shall be provided at EHV substations for controlling voltages within

the limits defined without resorting to switching-off of lines. The size of reactors should

be such that under steady state condition, switching on and off of the reactors shall not

cause a voltage change exceeding 5%. The standard sizes(MVAR) of reactors are:-

400 kV (3-ph units) 50, 63 & 80 at 420 kV

765 kv (1-ph units) 50, 63 & 110 at 800 kV

Fixed line reactors may be provided to control Temporary Power Frequency overvoltage

[after all voltage regulation has taken place] within the limits defined , under all probable

operating conditions.

Line reactors (switchable/controlled/fixed) may be provided if it is not possible to charge

EHV line without exceeding the voltage limits defined. The possibility of reducing pre-

charging voltage of the charging end shall also be considered in the context of

establishing the need for reactors.

Static VAR Compensation (SVC)

Static VAR compensation shall be provided where found necessary to damp the power

swings and provide the system stability under conditions defined. The dynamic range of

static compensators shall not be utilised under steady state operating conditions as far as

possible.




Sub-Station Planning Criteria

The requirements in respect of EHV sub-stations in a system such as the total load to be

catered by the sub-station of a particular voltage level, its MVA capacity, number of

feeders permissible etc. are important to the planners so as to provide an idea to them

about the time for going in for the adoption of next higher voltage level sub-station and

also the number of substations required for meeting a particular quantum of load.

Keeping these in view the following criteria have been laid down for planning an EHV

substation:

The maximum fault level on any new substation bus should not exceed 80% of the rated

rupturing capacity of the circuit breaker. The 20% margin is intended to take care of the

increase in short-circuit levels as the system grows. The rated breaking current capability

of switchgear at different voltage levels may be taken as:-

132 kV -- 25/31 kA

220 kV -- 31.5/40 kA

400 kV -- 40 kA

765 kV -- 40 kA

Higher breaking current capability would require major design change in the terminal

equipment and shall be avoided as far as possible.

The capacity of any single sub-station at different voltage levels shall not normally

exceed :-

765 kV -- 2500 MVA

400 kV -- 1000 MVA

220 kV -- 320 MVA

132 kV -- 150 MVA

Size and number of interconnecting transformers (ICTs) shall be planned in such a way

that the outage of any single unit would not overload the remaining ICT(s) or the

underlying system.

A stuck breaker condition shall not cause disruption of more than four feeders for 220 kV

system and two feeders for 400 kV system and one feeder for 765 kV system.




HDCT-4

Documents

Transcript of HDCT-4