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764 J. M. Carrasco et al.

• IGCTs are made like disk devices. They have to be cooled

with a cooling plate by electrical contact on the high volt-

age side. This is a problem because high electromagnetic

emission will occur. Another point of view is the num-

ber of allowed load cycles. Heating and cooling the device

will always bring mechanical stress to the silicon chip and

can be destroyed. This is a serious problem, especially in

wind turbine applications. On the other hand, IGBTs are

built like module devices. The silicon is isolated to the

cooling plate and can be connected to ground for low

electromagnetic emission even with higher switching fre-

quency. The base plate of this module is made of a special

material which has exactly the same thermal behavior as

silicon, so nearly no thermal stress occurs. This increases

the lifetime of the device by 10-fold approximately.

•

The main advantage of IGCTs versus IGBTs is that they

have a lower on state voltage drop, which is about 3.0 V

for a 4500 V device. In this case, the power dissipation due

to a voltage drop for a 1500 kW converter will be 2400 W

per phase. On the other hand, in the case of IGBT, the

voltage drop is higher than IGCTs. For a 1700 V device

having a drop of 5 V, and in this case the power dissipa-

tion due to the voltage drop for a 1500 kW condition will

be 5 kW per phase.

In conclusion, with the present semiconductor technology,

IGBTs present better characteristics, for frequency converters

in general and especially for wind turbine applications.

29.5.2 Power Converters

The technology of power electronic interfaces for variable-

speed wind turbines is focused on the following points:

• Development of high efﬁciency/high quality voltage

source AC/DC/AC converter for a main connection of

variable wind turbines, operating with either a permanent

magnet, a synchronous or an asynchronous generator.

• Operation at a power factor around one with higher-

harmonic voltage distortion less than international stan-

dards.

• The power quality of the electrical output of the wind

farms may be improved by the use of advanced static var

compensators STATCOM or active power ﬁlters using

power semiconductors like IGBTs, IGCTs, or GTOs.

These kind of power conditioning systems are a new

emerging family of FACTS (ﬂexible AC transmission sys-

tem) converters, which allow improved utilization of the

power network. These systems will allow wind farms to

reduce voltage drops and electrical losses in the network

without the possibility of transient over voltage at island-

ing due to self-excitation of wind generators. Moreover,

power conditioning systems equipment with different

control algorithm can be used to control the network

voltage, which will ﬂuctuate in response to the wind farm

output if the distribution network is weak [44, 45].

• For large power wind turbine applications where it is

necessary to increase the voltage level of the semiconduc-

tor of the power electronic interface, multilevel power

converter technology is emerging as a new breed of

power converter options for high-power applications.

The general structure of the multilevel converter is to syn-

thesize a sinusoidal voltage from several levels of voltages,

typically obtained from capacitor voltage sources. Addi-

tionally, these converters have better performance and

controllability because they use more than two voltage

levels [46–48].

29.5.3 Control Algorithms

A variable pitch and speed wind turbine is a very complex

non-lineal system. The control problem is more difﬁcult to

solve because some performance objectives, such as maximum

power captured, minimum mechanical stress, constant speed,

and power constant counteract each other. To solve this prob-

lem, a Fuzzy Logic control has recently been proposed. The

Fuzzy Logic controller implements a rule-based structure [49]

that can be easily adapted in order to optimize performance

control objectives and has been widely used in introduction

motor control applications [50–53]. In [54], a Fuzzy Logic

controller is used to optimize the power captured using max-

imum power tracking algorithms. Other original structures

have been proposed in [55]. The structure implements dif-

ferent control strategies depending on the rotor speed and

generates a current torque control action. Presently, more

complex control structures are being researched.

29.5.4 Offshore and Onshore Wind Turbines

One of the main trends in wind turbine technology is offshore

installations. There are great wind resources at sea for installing

wind turbines in many areas where the depth of the sea is rel-

atively shallow. There are several demonstration plants that

have had extremely positive results, so interest has increased

in installing offshore wind farms, because of the develop-

ment of large commercial power MW wind turbines. Offshore

wind turbines may have slightly more favorable energy balance

than onshore turbines, depending on local wind conditions.

In places where onshore wind turbines are typically placed on

ﬂat terrain, offshore wind turbines will generally yield some

50% more energy than a turbine placed on a nearby onshore

site. The reason is the low roughness of the sea surface. On the

other hand, the construction and installation of a foundation

requires 50% more energy than onshore turbines. It should

be remembered, however, that offshore wind turbines have a

longer life expectancy, around 25 to 30 years, than onshore

turbines. The reason is that the low turbulence at sea gives

lower fatigue loads on the wind turbine.

29 Wind Turbine Applications 765

From a power electronics point of view, offshore wind tur-

bines are interesting because, under certain circumstances,

they become desirable to transmit the generated power to the

load center over DC transmission lines (HVDC). This alterna-

tive becomes economically attractive versus AC transmission

when a large amount of power is to be transmitted over a

long distance from a remote wind farm to the load center [8].

Moreover, the transient stability and the dynamic damping of

the electrical system oscillations can be improved by HVDC

transmissions.

Nomenclature

DC link capacitor.

(λ, β) Power coefﬁcient at tip speed ratio λ and pitch β.

, e

Instantaneous values of grid voltages.

, e

Grid voltages expressed in an orthogonal reference

frame.

Excitation frequency (the same as the grid fre-

quency) in hertz.

Frequency of the voltage supplied to the rotor of

machine 2 in hertz.

G Gearbox ratio.

DC inductor current of the step-up converter.

ref

Desired DC inductor current of the step-up

converter.

dse

, i

qse

Instantaneous values of the direct and quadrature-

axis stator current components, respectively, and

expressed in rotor-ﬂux-oriented reference frame.

ref

dse

, i

ref

qse

Desired instantaneous values of the direct

and quadrature-axis stator current components,

respectively, and expressed in rotor-ﬂux-oriented

reference frame.

dsr

, i

qsr

Stator current components established in the

rotor reference frame.

ref

dsr

, i

ref

qsr

Desired stator current components established in

the rotor reference frame.

, i

Instantaneous values of the direct and quadrature-

axis stator current components, respectively, and

expressed in the rotor reference phase.

, i

Instantaneous values of the direct and quadrature-

axis stator current components, respectively, and

expressed in the stator reference frame.

ref

, i

ref

Desired direct and quadrature-axis stator cur-

rent components expressed in the stator reference

frame.

exc

Synchronous generator excitation current.

ref

exc

Desired synchronous generator excitation current.

ref

, i

ref

, i

ref

Desired stator current.

, i

Rotor current.

, i

Stator current.

ref

, i

ref

, i

ref

Desired stator current.

, i

Public grid phase currents.

ref

Desired magnetizing current.

Magnetizing current.

dsm

, i

qsm

Instantaneous values of the direct and quadrature-

axis magnetizing stator current components,

respectively, and expressed in the magnetizing

current-oriented reference frame.

J Total inertia of the system referred to the high

speed shaft.

, k

Winding factors of rotor and stator.

Coupled inductance.

Inductance of inductors at the AC side of the

inverter.

, L

Stator and rotor windings inductances.

Inductance of the step-up chopper.

n Turns ratio of the machine. n = k

·n

, n

Number of turns of each rotor and stator phase.

Angular speed of the magnetic ﬁeld (synchronous

speed) expressed in rpm.

Angular speed of the generator rotor expressed in

rpm.

p Number of pole pairs.

, p

Number of pole pairs of machine number 1 and

Electrical power in the stator of principal machine

number 1.

Electrical power in the stator of auxiliary machine

number 2.

Electrical generated power.

Mechanical power in the low speed shaft.

max

Generated maximum power.

rate

Generator rate power.

, Q

Active and reactive power through the stator.

ref

, Q

ref

Desired active and reactive power through the

stator.

slip

Slip power.

Available wind power.

ref

, q

ref

Desired real power and desired reactive power on

the grid side.

Electromagnetic torque of the machine.

ref

Desired electromagnetic torque of the machine.

Torque in the low speed shaft.

rate

Generator rate torque.

Torque in the high speed shaft.

R Rotor radius.

, R

Stator and rotor winding resistors.

s Slip.

= ω

−ω

/ω

Slips of machine principal number 1.

= ω

−ω

/ω

Slips of machine principal number 2.

, T

Stator and rotor time constants, respectively.

ref

dse

, u

ref

qse

Desired direct and quadrature-axis stator volt-

age expressed in the rotor-ﬂux-oriented reference

frame.

ref

, u

ref

Desired direct and quadrature-axis stator voltage

expressed in the stator reference frame.

766 J. M. Carrasco et al.

, u

Rotor voltage.

, u

Stator voltage.

ref

, u

ref

, u

ref

Desired stator voltage.

, i

, λ

Rotor voltage, current, and ﬂux, respectively,

referred to a reference frame that rotates with the

rotor.



, i



, λ



Rotor voltage, current, and ﬂux, respectively,

referred to a reference frame ﬁxed with the stator.

, i

, λ

Stator voltage, current, and ﬂux, respectively,

referred to a reference frame ﬁxed with the stator.

, u

Direct and quadrature-axis stator voltage

expressed in the magnetizing current reference

frame.

rat

Rated wind speed.

max

Maximum power wind speed.

start

Start wind speed.

stop

Stop wind speed.

Wind speed.

DC-Link capacitor voltage.

ref

Desired DC-Link capacitor voltage.

max

Maximum RMS stator voltage of the synchronous

generator.

min

Maximum RMS stator voltage of the synchronous

generator.

β Pitch angle.

ref

Desired pitch angle.

δ Load angle.

λ = ω · R/V

Tip speed ratio.

opt

Optimal tip speed ratio.

Magnetizing ﬂux linkage vector.

, λ

Instantaneous values of the direct and quadra-

ture axis magnetizing ﬂux linkage components

expressed in the rotor reference frame.

Estimated modulus of magnetizing ﬂux linkage

vector.



ref



Desired modulus of magnetizing ﬂux linkage

vector.

η Electrical performance.

Phase angle of the rotor ﬂux linkage space pha-

sor with respect to the direct axis of the stator

reference frame.

Magnetizing current angle.

Angle corresponding to the angular slip frequency.

Rotor angle.

ρ Air density.

= 2πf

Angular speed of the rotating magnetic ﬂux pro-

duced in the stator of machine 1 relative to the

stator.

= 2πf

Angular speed of the rotating magnetic ﬂux pro-

duced in the rotor of machine 2 relative to the

rotor.

Low-speed shaft angular speed.

Angular speed of the generator rotor.

ref

Reference rotor speed.

max

Maximum angular speed of the synchronous

generator.

min

Minimum angular speed of the synchronous gen-

erator.

ref

Desired angular speed for the torque controller.

ref

Desired angular speed for the pitch controller.

rate

Rated value of the rotor speed.

Electrical angular speed of the magnetizing cur-

rent reference frame.

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IFSA’99.

HVDC Transmission

Vijay K. Sood, Ph.D.

Hydro-Quebec (IREQ), 1800 Lionel

Boulet, Varennes, Quebec,

Canada

30.1 Introduction .......................................................................................... 769

30.1.1 Comparison of AC–DC Transmission • 30.1.2 Evaluation of Reliability and Availability

Costs • 30.1.3 Applications of DC Transmission • 30.1.4 Types of HVDC Systems

30.2 Main Components of HVDC Converter Station ........................................... 775

30.2.1 Converter Unit • 30.2.2 Converter Transformer • 30.2.3 Filters • 30.2.4 Reactive Power

Source • 30.2.5 DC Smoothing Reactor • 30.2.6 DC Switchgear • 30.2.7 DC Cables

30.3 Analysis of Converter Bridge..................................................................... 778

30.4 Controls and Protection........................................................................... 778

30.4.1 Basics of Control for a Two-terminal DC Link • 30.4.2 Control Implementation

• 30.4.3 Control Loops • 30.4.4 Hierarchy of DC Controls • 30.4.5 Monitoring of Signals

• 30.4.6 Protection against Overcurrents • 30.4.7 Protection against Overvoltages

30.5 MTDC Operation ................................................................................... 786

30.5.1 Series Tap • 30.5.2 Parallel Tap • 30.5.3 Control of MTDC System

30.6 Application ............................................................................................ 787

30.6.1 HVDC Interconnection at Gurun (Malaysia)

30.7 Modern Trends ...................................................................................... 789

30.7.1 Converter Station Design of the 2000s

30.8 HVDC System Simulation Techniques........................................................ 792

30.8.1 DC Simulators and TNAs [9] • 30.8.2 Digital Computer Analysis

30.9 Concluding Remarks ............................................................................... 794

References ............................................................................................. 795

30.1 Introduction

High voltage direct current (HVDC) transmission [1–3] is

a major user of power electronics technology. The HVDC

technology ﬁrst made its mark in the early undersea cable

interconnections of Gotland (1954) and Sardinia (1967), and

then in long distance transmission with the Paciﬁc Intertie

(1970) and Nelson River (1973) schemes using mercury arc

valves. A signiﬁcant milestone development occurred in 1972

with the ﬁrst back-to-back (BB) asynchronous interconnec-

tion at Eel River between Quebec and New Brunswick; this

installation also marked the introduction of thyristor valves to

the technology and replaced the earlier mercury arc valves.

Until 2005, a total transmission capacity of 70,000 MW

HVDC is installed in some 95 projects all over the

world. To understand the rapid growth of dc transmission

(Table 30.1) [4] in the past 50 years, it is ﬁrst necessary to

compare it to conventional ac transmission.

30.1.1 Comparison of AC–DC Transmission

Making a planning selection between either ac or dc transmis-

sion is based on an evaluation of transmission costs, technical

considerations, and the reliability/availability offered by the

two power transmission alternatives.

30.1.1.1 Evaluation of Transmission Costs

The cost of a transmission line comprises of the capital invest-

ment required for the actual infrastructure (i.e. right-of-way

(ROW), towers, conductors, insulators, and terminal equip-

ment) and costs incurred for operational requirements (i.e.

losses). Assuming similar insulation requirements for peak

voltage levels for both ac and dc lines, a dc line can carry

as much power, with two conductors (having positive/negative

polarities with respect to ground), as an ac line with three con-

ductors of the same size. Therefore, for a given power level, a

dc line requires a smaller ROW, simpler and cheaper towers

769

770 V. K. Sood

TABLE 30.1 Listing of HVDC installations

HVDC link Supplier Year Power (MW) DC voltage (kV) Length (km) Location

Gotland I

A 1954 20 ±100 96 Sweden

English channel A 1961 160 ±100 64 England–France

Volgograd–Donbass

∗

Unknown Russian

manufacturer

1965 720 ±400 470 Russia

Inter-island A 1965 600 ±250 609 New Zealand

Konti-Skan I A 1965 250 250 180 Denmark–Sweden

Sakuma A 1965 300 2 × 125 B-B

∗∗∗

Japan

Sardinia I 1967 200 200 413 Italy

Vancouver I A 1968 312 260 69 Canada

Paciﬁc intertie JV 1970 1440 ±400 1362 U.S.A.

Paciﬁc intertie JV 1982 1600 ±400 1362 U.S.A

Nelson River I

∗∗

I 1972 1620 ±450 892 Canada

Kingsnorth I 1975 640 ±260 82 England

Gotland A 1970 30 ±150 96 Sweden

Eel River C 1972 320 2 × 80 B-B Canada

Skagerrak I A 1976 250 250 240 Norway–Denmark

Skagerrak II A 1977 500 ±250 Norway–Denmark

Skagerrak III A 1993 440 350 240 Norway–Denmark

Vancouver II C 1977 370 −280 77 Canada

Shin-Shinano D 1977 300 2 ×125 B-B Japan

Shin-Shinano D 1992 600 3 ×125 B-B Japan

Square Butte C 1977 500 ±250 749 U.S.A.

David A. Hamil C 1977 100 50 B-B U.S.A.

Cahora Bassa J 1978 1920 ±533 1360 Mozambique-S. Africa

Nelson River II J 1978 900 ±250 930 Canada

Nelson River II J 1985 1800 ±500 930 Canada

CU Project A 1979 1000 ±400 710 U.S.A.

Hokkaido–Honshu E 1979 150 125 168 Japan

1980 300 250

1993 600 ±250

Acaray G 1981 50 25.6 B-B Paraguay

Vyborg F 1981 355 1 × 170(±85) B-B Russia (tie w/Finland)

Vyborg F 1982 710 2 × 170

Vyborg F 1065 3 × 170

Duernrohr J 1983 550 145 B-B Austria

Gotland II A 1983 130 150 100 Sweden

Gotland III A 1987 260 ±150 103 Sweden

Eddy County C 1983 200 82 B-B U.S.A.

Chateauguay J 1984 1000 2 ×140 B-B Canada

Oklaunion C 1984 200 82 B-B U.S.A.

Itaipu A 1984 1575 ±300 785 Brazil

Itaipu A 1985 2383 785 Brazil

Itaipu A 1986 3150 ±600 785 Brazil

Inga-Shaba A 1982 560 ±500 1700 DR Congo

Paciﬁc Intertie upgrade A 1984 2000 ±500 1362 U.S.A.

Blackwater B 1985 200 57 B-B U.S.A.

Highgate A 1985 200 ±56 B-B U.S.A.

Madawaska C 1985 350 140 B-B Canada

Miles City C 1985 200 ±82 B-B U.S.A.

Broken Hill A 1986 40 2 ×17(±8.33) B-B Australia

Intermountain power

project

A 1986 1920 ±500 784 U.S.A.

Cross-channel:

(Les Mandarins) H 1986 1000 ±270 72 France–England

(Sellindge) I 1986 2000 2 ×±270

Des Cantons-Comerford C 1986 690 ±450 172 Canada-U.S.A.

Sacoi

H 1986 200 200 415 Corsica Island, Italy

Sacoi

###

H 1992 300

30 HVDC Transmission 771

TABLE 30.1—Contd

HVDC link Supplier Year Power (MW) DC Voltage (kV) Length (km) Location

Itaipu II A 1987 3150 ±600 805 Brazil

Sidney (Virginia Smith) G 1988 200 55.5 B-B U.S.A.

Gezhouba–Shanghai B+G 1989 600 500 1000 China

1990 1200 ±500

Konti-Skan II A 1988 300 285 150 Sweden–Denmark

Vindhyachal A 1989 500 2 ×69.7 B-B India

Paciﬁc Intertie Exp. B 1989 1100 ±500 1362 U.S.A.

McNeill I 1989 150 42 B-B Canada

Fenno-Skan A 1989 500 400 200 Finland–Sweden

Sileru–Barsoor K 1989 100 +100 196 India

200 +200

400 ±200

Rihand-Delhi A 1991 1500 ± 500 India

Quebec-New England A 1990 2000

∗∗∗∗

±450 1500 Canada-U.S.A.

Nicolet Tap A 1992 1800 Canada

DC Hybrid Link AB 1992 992 +270/−350 617 New Zealand

Etzenricht G 1993 600 160 B-B Germany (tie w/Czech)

Vienna-South east G 1993 600 145 B-B Austria (tie w/Hungary)

Haenam–Cheju I 1993 300 ±180 100 South Korea

Baltic Cable Project AB 1994 600 450 Sweden-Germany

Welch–Monticello AB 1995 600 450 B-B U.S.A.

Kontek Interconnection G 1995 600 400 170 Denmark–Germany

Scotland–N. Ireland G 1996 250 250 United Kingdom

Chandrapur–Ramagundum I 1996 1000 2 ×500 B-B India

Chandrapur–Padghe AB 1997 1500 ±500 900 India

Greece–Italy AB 1997 500 400 200, sea Italy

Gazuwaka–Jeypore AB 1997 500 B-B India

Leyte-Luzun AB 1997 1600 400 440 Philippines

Cahora Bassa G 1998 1920 ±533 1456 Mozambique–S.Africa

TSQ-Beijao G 2000 1800 ±500 903 China

Thailand–Malaysia G 2001 300 ±300 B-B Thailand–Malaysia

Moyle G 2001 2 ×250 250 64 Ireland–Scotland

East-South Intercon. G 2003 2000 ±500 1450 India

Rapid City DC tie AB 2003 2 × 100 ±13 B-B S.Dakota, U.S.A.

Three Gorges-Changzhou AB 2003 3000 ±500 890 China

Three Gorges-Quangdong AB 2004 3000 ±500 940 China

Guizhou-Guangdong G 2004 3000 ±500 940 China

Celilo Conv. station AB 2004 2000 ±500 upgrade U.S.A.

Nelson River Bipole II G 2004 1000 450 Pole 1 Canada

Basslink G 2005 500 400 350 Australia–Tasmania

Lamar G 2005 210 63.6 B-B Colorado, U.S.A.

Vizag II AB 2005 500 ±88 B-B India

Estlink AB 2006 350 ±150 HVDC Light Estonia – Finland

Three Gorges-Shanghai AB 2007 3000 ±500 1059 China

NorNed AB 2007 700 ±450 560 Norway – Netherlands

Valhall offshore AB 2009 950 HVDC Light Norway

A – ASEA; B – Brown Boveri; C – General Electric; D – Toshiba; E – Hitachi; F – Russian; G – Siemens; H – CGEE Alsthom; I – GEC (Formerly English Electric);

J – HVDC Working Group. (AEG, BBC, Gmens); K – (Independent); AB – ABB (ASEA Brown Boveri); JV – Joint Venture (GE and ASEA);

∗

two valve groups

replaced with thyristors in 1977;

∗∗

two valve groups in Pole 1 replaced with thyristors by GEC in 1991;

∗∗∗

Back-to-back HVDC System;

∗∗∗∗

Multiterminal

system. Largest terminal is rated 2250 MW;

Retired from service;

50 MW thyristor tap;

###

Uprated w/thyristor valves.

772 V. K. Sood

± 500 kV DC

ROW: 60 m

800 kV AC

ROW: 85 m

2 x 500 kV AC

ROW: 100 m

Right-of-Way

Typical DC and AC Transmission Line Structures

for approx. 2000 MW

FIGURE 30.1 Comparison of ROW for ac and dc transmission systems.

and reduced conductor and insulator costs. As an example,

Fig. 30.1 shows the comparative case of ac and dc systems

carrying 2000 MW.

With the dc option, since there are only two conductors

(with the same current capacity of three ac conductors), the

power transmission losses are also reduced to about two-thirds

of the comparable ac system. The absence of skin effect with

dc is also beneﬁcial in reducing power losses marginally, and

the dielectric losses, in case of power cables is also very much

less for dc transmission.

Corona effects tend to be less signiﬁcant on dc than for

ac conductors. The other factors that inﬂuence line costs are

the costs of compensation and terminal equipment. DC lines

do not require reactive power compensation but the termi-

nal equipment costs are increased due to the presence of

converters and ﬁlters.

Figure 30.2 shows the variation of infrastructure costs with

distance for ac and dc transmission. AC tends to be more

Costs

breakeven distance

DC line costs

Distance

AC line costs

AC terminal costs

DC terminal

costs

FIGURE 30.2 Comparison of ac and dc transmission system costs.

economical than dc for distances less than the “breakeven dis-

tance” but is more expensive for longer distances. This is due

to a combination of the terminal equipment costs and line

costs for the two types of transmission. The breakeven dis-

tances can vary from about 500 to 800 km in overhead lines

depending on the per unit line costs. With a cable system, this

breakeven distance approaches 50 km.

30.1.1.2 Evaluation of Technical Considerations

Due to its fast controllability, a dc transmission system has full

control over transmitted power, an ability to enhance transient

and dynamic stability in associated ac networks and can limit

fault currents in the dc lines. Furthermore, dc transmission

overcomes some of the following problems associated with ac

transmission:

Stability limits

The power transfer in an ac line is dependent on the angular

difference between the voltage phasors at the two line ends.

For a given power transfer level, this angle increases with

distance. The maximum power transfer is limited by the con-

siderations of steady state and transient stability. The power

carrying capability of an ac line is inversely proportional to

transmission distance whereas the power carrying ability of dc

lines is unaffected by the distance of transmission.

Voltage control

Voltage control in ac lines is complicated by the line charging

requirements and voltage drops. The voltage proﬁle in an ac

line is relatively ﬂat only for a ﬁxed level of power transfer,

corresponding to its surge impedance loading (SIL). The volt-

age proﬁle varies with the line loading. For constant voltage at

the line ends, the midpoint voltage is reduced for line loadings

higher than SIL and increased for loadings lesser than SIL.

30 HVDC Transmission 773

The maintenance of constant voltage at the two ends

requires reactive power control as the line loading is increased.

The reactive power requirements increase with line length.

Although dc converter stations require reactive power

related to the power transmitted, the dc line itself does not

require any reactive power.

The steady-state charging currents in ac cables pose seri-

ous problems and make the breakeven distance for cable

transmission around 50 km.

Line compensation

Line compensation is necessary for long distance ac transmis-

sion to overcome the problems of line charging and stability

limitations. The increase in power transfer and voltage con-

trol is possible through the use of shunt inductors, series

capacitors, static var compensators (SVCs), and lately, the new

generation static compensators (STATCOMs).

In the case of dc lines, such compensation is not needed.

Problems of ac interconnection

The interconnection of two power systems through ac ties

requires the automatic generation controllers of both systems

to be coordinated using tie line power and frequency signals.

Even with coordinated control of interconnected systems, the

operation of ac ties can be problematic due to (a) the presence

of large power oscillations which can lead to frequent tripping,

(b) increase in fault level, and (c) transmission of disturbances

from one system to the other.

The fast controllability of power ﬂow in dc lines eliminates

all of the above problems. Furthermore, the asynchronous

interconnection of two power systems can only be achieved

with the use of dc links.

Ground impedance

In ac transmission, the existence of ground (zero sequence)

current cannot be permitted in steady state due to the

high magnitude of ground impedance that will not only

affect efﬁcient power transfer, but also result in telephonic

interference.

The ground impedance is negligible for dc currents and a

dc link can operate using one conductor with ground return

(monopolar operation). The ground return is objectionable

only when buried metallic structures (such as pipelines) are

present and are subject to corrosion with dc current ﬂow. It

is to be noted that even while operating in the monopolar

mode, the ac network, feeding the dc converter station oper-

ates with balanced voltages and currents. Hence, single-pole

operation of dc transmission systems is possible for extended

periods, while in ac transmission single-phase operation (or

any) unbalanced operation is not feasible for more than a

second.

Problems of dc transmission

The application of dc transmission is limited by factors such

as:

1. High cost of conversion equipment.

2. Inability to use transformers to alter voltage levels.

3. Generation of harmonics.

4. Requirement of reactive power.

5. Complexity of controls.

Over the years, there have been signiﬁcant advances in dc

technology, which have tried to overcome the disadvantages

listed above, except for item 2. These are:

1. Increase in the ratings of a thyristor cell that makes up

a valve.

2. Modular construction of thyristor valves.

3. Twelve-pulse operation of converters.

4. Use of force-commutation.

5. Application of digital electronics and ﬁber optics in the

control of converters.

Some of the above advances have resulted in improving the

reliability and reduction of conversion costs in dc systems.

30.1.2 Evaluation of Reliability and Availability

Costs

Statistics on the reliability of HVDC links are maintained by

CIGRE and IEEE Working Groups. The reliability of dc links

has been very good and is comparable with ac systems. The

availability of dc links is quoted in the upper 90%.

30.1.3 Applications of DC Transmission

Due to their costs and special nature, most applications of

dc transmission generally fall into one of the following four

categories:

Underground or underwater cables

In the case of long-cable connections over the breakeven dis-

tance of about 40–50 km, the dc cable transmission system has

a marked advantage over the ac cable connections. Examples of

this type of applications were the Gotland (1954) and Sardinia

(1967) schemes.

The recent development of voltage source converters (VSCs)

and the use of rugged polymer dc cables, with the so-called

“HVDC Light” option, are being increasingly considered. An

example of this type of application is the180 MW Directlink

connection (2000) in Australia.

Long distance bulk power transmission

Bulk power transmission over long distances is an application

ideally suited for dc transmission and is more economical than

ac transmission whenever the breakeven distance is exceeded.