paper title: the abcs of hvdc transmission technology ... · er the ac system or the further the...

Paper title: The ABCs of HVDC Transmission Technology Copyright © 2007 IEEE. Published in: IEEE Power & Energy Magazine March/April 2007 Vol. 5 No. 2 This material is posted here with permission of the IEEE. Such permission of the IEEE does not in any way imply IEEE endorsement of any of ABB Power Technologies AB’s products or services. Internal or personal use of this material is permitted. However, permission to reprint/republish this material for advertising or promotional purposes or for creating new collective works for resale or redistribution must be obtained from the IEEE by writing to [email protected]. By choosing to view this document, you agree to all provisions of the copyright laws protecting it.

march/april 2007 IEEE power & energy magazine 33

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©PHOTODISC

HIGH VOLTAGE DIRECT CURRENT (HVDC) TECHNOLOGY HAScharacteristics that make it especially attractive for certain transmission applica-tions. HVDC transmission is widely recognized as being advantageous forlong-distance bulk-power delivery, asynchronous interconnections, and longsubmarine cable crossings. The number of HVDC projects committed or underconsideration globally has increased in recent years reflecting a renewed inter-est in this mature technology. New converter designs have broadened the poten-tial range of HVDC transmission to include applications for underground,offshore, economic replacement of reliability-must-run generation, and voltagestabilization. This broader range of applications has contributed to the recentgrowth of HVDC transmission. There are approximately ten new HVDC proj-ects under construction or active consideration in North America along with

many more projects underway globally. Figure 1 shows the Dan-ish terminal for Skagerrak’s pole 3, which is rated 440 MW. Fig-

ure 2 shows the ±500-kV HVDC transmission line for the 2,000MW Intermountain Power Project between Utah and California.

This article discusses HVDC technologies, application areas whereHVDC is favorable compared to ac transmission, system configura-

tion, station design, and operating principles.

Core HVDC TechnologiesTwo basic converter technologies are used in modern HVDC transmis-

sion systems. These are conventional line-commutated current sourceconverters (CSCs) and self-commutated voltage source converters

(VSCs). Figure 3 shows a conventional HVDC converter station withCSCs while Figure 4 shows a HVDC converter station with VSCs.

Line-Commutated Current Source ConverterConventional HVDC transmission employs line-commutated CSCs with

thyristor valves. Such converters require a synchronous voltage source in orderto operate. The basic building block used for HVDC conversion is the three-phase, full-wave bridge referred to as a six-pulse or Graetz bridge. The termsix-pulse is due to six commutations or switching operations per period result-ing in a characteristic harmonic ripple of six times the fundamental frequencyin the dc output voltage. Each six-pulse bridge is comprised of six controlledswitching elements or thyristor valves. Each valve is comprised of a suitablenumber of series-connected thyristors to achieve the desired dc voltage rating.

The dc terminals of two six-pulse bridges with ac voltage sources phase dis-placed by 30◦ can be connected in series to increase the dc voltage and elimi-nate some of the characteristic ac current and dc voltage harmonics. Operationin this manner is referred to as 12-pulse operation. In 12-pulse operation, thecharacteristic ac current and dc voltage harmonics have frequencies of 12n ± 1and 12n, respectively. The 30◦ phase displacement is achieved by feeding onebridge through a transformer with a wye-connected secondary and the otherbridge through a transformer with a delta-connected secondary. Most modernHVDC transmission schemes utilize 12-pulse converters to reduce the harmon-ic filtering requirements required for six-pulse operation; e.g., fifth and seventhon the ac side and sixth on the dc side. This is because, although these harmon-ic currents still flow through the valves and the transformer windings, they are

180◦ out of phase and cancel out on the primary side of theconverter transformer. Figure 5 shows the thyristor valvearrangement for a 12-pulse converter with three quadruplevalves, one for each phase. Each thyristor valve is built upwith series-connected thyristor modules.

Line-commutated converters require a relatively strongsynchronous voltage source in order to commutate. Commu-

tation is the transfer of current from one phase to another in asynchronized firing sequence of the thyristor valves. Thethree-phase symmetrical short circuit capacity available fromthe network at the converter connection point should be atleast twice the converter rating for converter operation. Line-commutated CSCs can only operate with the ac current lag-ging the voltage, so the conversion process demands reactivepower. Reactive power is supplied from the ac filters, whichlook capacitive at the fundamental frequency, shunt banks, orseries capacitors that are an integral part of the converter sta-tion. Any surplus or deficit in reactive power from these localsources must be accommodated by the ac system. This differ-ence in reactive power needs to be kept within a given bandto keep the ac voltage within the desired tolerance. The weak-er the ac system or the further the converter is away fromgeneration, the tighter the reactive power exchange must beto stay within the desired voltage tolerance. Figure 6 illus-trates the reactive power demand, reactive power compensa-tion, and reactive power exchange with the ac network as afunction of dc load current.

Converters with series capacitors connected between thevalves and the transformers were introduced in the late 1990sfor weak-system, back-to-back applications. These convertersare referred to as capacitor-commutated converters (CCCs).The series capacitor provides some of the converter reactivepower compensation requirements automatically with loadcurrent and provides part of the commutation voltage,improving voltage stability. The overvoltage protection of theseries capacitors is simple since the capacitor is not exposedto line faults, and the fault current for internal converter faultsis limited by the impedance of the converter transformers.The CCC configuration allows higher power ratings in areaswere the ac network is close to its voltage stability limit. Theasynchronous Garabi interconnection between Brazil andArgentina consists of 4 × 550 MW parallel CCC links. The

Rapid City Tie between the Eastern andWestern interconnected systems con-sists of 2 × 100 MW parallel CCClinks (Figure 7). Both installations usea modular design with converter valveslocated within prefabricated electricalenclosures rather than a conventionalvalve hall.

Self-Commutated VoltageSource Converter HVDC transmission using VSCs withpulse-width modulation (PWM), com-mercially known as HVDC Light, wasintroduced in the late 1990s. Sincethen the progression to higher voltageand power ratings for these convertershas roughly paralleled that for thyris-tor valve converters in the 1970s.These VSC-based systems are self-

34 IEEE power & energy magazine march/april 2007

figure 1. HVDC converter station with ac filters in theforeground and valve hall in the background.

figure 2. A ±500-kV HVDC transmission line.

figure 3. Conventional HVDC with current source converters.

ac dc

HVDC-CSC

Indoor

Outdoor

aac Filters

ddc Filters

Thyristor Valves

ConverterTransformers

march/april 2007 IEEE power & energy magazine

commutated with insulated-gate bipolar transistor (IGBT)valves and solid-dielectric extruded HVDC cables. Figure 8illustrates solid-state converter development for the two dif-ferent types of converter technologies using thyristor valvesand IGBT valves.

HVDC transmission with VSCs can be beneficial to over-all system performance. VSC technology can rapidly controlboth active and reactive power independently of one another.Reactive power can also be controlled at each terminal inde-pendent of the dc transmission voltage level. This controlcapability gives total flexibility to place converters anywherein the ac network since there is no restriction on minimumnetwork short-circuit capacity. Self-commutation with VSCeven permits black start; i.e., the converter can be used tosynthesize a balanced set of three phase voltages like a virtualsynchronous generator. The dynamic support of the ac volt-age at each converter terminal improves the voltage stabilityand can increase the transfer capabilityof the sending- and receiving-end acsystems, thereby leveraging the transfercapability of the dc link. Figure 9shows the IGBT converter valvearrangement for a VSC station. Figure10 shows the active and reactive poweroperating range for a converter stationwith a VSC. Unlike conventionalHVDC transmission, the convertersthemselves have no reactive powerdemand and can actually control theirreactive power to regulate ac systemvoltage just like a generator.

HVDC ApplicationsHVDC transmission applications canbe broken down into different basic cat-egories. Although the rationale forselection of HVDC is often economic,there may be other reasons for its selec-tion. HVDC may be the only feasibleway to interconnect two asynchronousnetworks, reduce fault currents, utilizelong underground cable circuits, bypassnetwork congestion, share utility rights-of-way without degradation of reliabili-ty, and to mitigate environmentalconcerns. In all of these applications,HVDC nicely complements the actransmission system.

Long-Distance Bulk PowerTransmissionHVDC transmission systems often pro-vide a more economical alternative to actransmission for long-distance bulk-power delivery from remote resources

such as hydroelectric developments, mine-mouth powerplants, or large-scale wind farms. Higher power transfers arepossible over longer distances using fewer lines with HVDCtransmission than with ac transmission. Typical HVDC linesutilize a bipolar configuration with two independent poles,one at a positive voltage and the other at a negative voltagewith respect to ground. Bipolar HVDC lines are comparableto a double circuit ac line since they can operate at half powerwith one pole out of service but require only one-third thenumber of insulated sets of conductors as a double circuit acline. Automatic restarts from temporary dc line fault clearingsequences are routine even for generator outlet transmission.No synchro-checking is required as for automatic reclosuresfollowing ac line faults since the dc restarts do not expose tur-bine generator units to high risk of transient torque amplifica-tion from closing into faults or across high phase angles. Thecontrollability of HVDC links offer firm transmission capacity

35

figure 4. HVDC with voltage source converters.

ac dc

HVDC-VSCHVDC-VSC

Indoor

Outdoor

IGBT Valves IGBT Valves

figure 5. Thyristor valve arrangement for a 12-pulse converter with threequadruple valves, one for each phase.

DoubleValve

Thyristor Module

Single QuadrupleValve Thyristors

without limitation due to network congestion or loop flow onparallel paths. Controllability allows the HVDC to “leap-frog”multiple “choke-points” or bypass sequential path limits in theac network. Therefore, the utilization of HVDC links is usual-ly higher than that for extra high voltage ac transmission, low-ering the transmission cost per MWh. This controllability canalso be very beneficial for the parallel transmission since, byeliminating loop flow, it frees up this transmission capacity forits intended purpose of serving intermediate load and provid-ing an outlet for local generation.

Whenever long-distance transmission is discussed, theconcept of “break-even distance” frequently arises. This iswhere the savings in line costs offset the higher converter sta-tion costs. A bipolar HVDC line uses only two insulated setsof conductors rather than three. This results in narrowerrights-of-way, smaller transmission towers, and lower linelosses than with ac lines of comparable capacity. A roughapproximation of the savings in line construction is 30%.

Although break-even distance is influenced by the costsof right-of-way and line construction with a typical value of500 km, the concept itself is misleading because in manycases more ac lines are needed to deliver the same powerover the same distance due to system stability limitations.

Furthermore, the long-distance ac linesusually require intermediate switching sta-tions and reactive power compensation.This can increase the substation costs for actransmission to the point where it is compa-rable to that for HVDC transmission.

For example, the generator outlet trans-mission alternative for the ±250-kV, 500-MW Square Butte Project was two 345-kVseries-compensated ac transmission lines.The 12,600-MW Itaipu project has half itspower delivered on three 800-kV series-compensated ac lines (three circuits) and theother half delivered on two ±600-kV bipolar

HVDC lines (four circuits). Similarly, the ±500-kV, 1,600-MW Intermountain Power Project (IPP) ac alternative com-prised two 500-kV ac lines. The IPP takes advantage of thedouble-circuit nature of the bipolar line and includes a 100%short-term and 50% continuous monopolar overload. The first6,000-MW stage of the transmission for the Three GorgesProject in China would have required 5 × 500-kV ac lines asopposed to 2 × ±500-kV, 3,000-MW bipolar HVDC lines.

Table 1 contains an economic comparison of capital costsand losses for different ac and dc transmission alternatives fora hypothetical 750-mile, 3,000-MW transmission system. Thelong transmission distance requires intermediate substationsor switching stations and shunt reactors for the ac alternatives.The long distance and heavy power transfer, nearly twice thesurge-impedance loading on the 500-kV ac alternatives,require a high level of series compensation. These ac stationcosts are included in the cost estimates for the ac alternatives.

It is interesting to compare the economics for transmis-sion to that of transporting an equivalent amount of energyusing other transport methods, in this case using rail trans-portation of sub-bituminous western coal with a heat contentof 8,500 Btu/lb to support a 3,000-MW base load powerplant with heat rate of 8,500 Btu/kWh operating at an 85%


figure 6. Reactive power compensation for conventional HVDC converterstation.

Converter

FilterClassic

Q

0,5

0,13

ShuntBanks

HarmonicFilters

Unbalance1.0

ld

figure 7. Asynchronous back-to-back tie with capacitor-commutated converter near Rapid City, South Dakota.

ValveEnclosures

CommutationCapacitor

ConverterTransformer

Ua

Ub

Uc

++

+

+

+

++

++

Ula Uca

Ucb

Ucc

Ulb

Ulc

la

ld

lb

lc

1 3 5

4 6 2


load factor. The rail route is assumedto be longer than the more directtransmission route; i.e., 900 miles.Each unit train is comprised of 100cars each carrying 100 tons of coal.The plant requires three unit trains perday. The annual coal transportationcosts are about US$560 million peryear at an assumed rate of US$50/ton.This works out to be US$186kW/year and US$25 per MWh. Theannual diesel fuel consumed in theprocess is in excess of 20 million gal-lons at 500 net ton-miles per gallon.The rail transportation costs are sub-ject to escalation and congestionwhereas the transmission costs arefixed. Furthermore, transmission isthe only way to deliver remote renew-able resources.

Underground and Submarine Cable TransmissionUnlike the case for ac cables, there is no physicalrestriction limiting the distance or power level forHVDC underground or submarine cables. Under-ground cables can be used on shared rights-of-way with other utilities without impactingreliability concerns over use of common corridors.For underground or submarine cable systemsthere is considerable savings in installed cablecosts and cost of losses when using HVDC trans-mission. Depending on the power level to betransmitted, these savings can offset the higherconverter station costs at distances of 40 km ormore. Furthermore, there is a drop-off in cablecapacity with ac transmission over distance due toits reactive component of charging current sincecables have higher capacitances and lower inductances than acoverhead lines. Although this can be compensated by interme-diate shunt compensation for underground cables at increasedexpense, it is not practical to do so for submarine cables.

For a given cable conductor area, the line losses withHVDC cables can be about half those of ac cables. This isdue to ac cables requiring more conductors (three phases),carrying the reactive component of current, skin-effect, andinduced currents in the cable sheath and armor.

With a cable system, the need to balance unequal loadingsor the risk of postcontingency overloads often necessitatesuse of a series-connected reactors or phase shifting trans-formers. These potential problems do not exist with a con-trolled HVDC cable system.

Extruded HVDC cables with prefabricated joints usedwith VSC-based transmission are lighter, more flexible, andeasier to splice than the mass-impregnated oil-paper cables

(MINDs) used for conventional HVDC transmission, thusmaking them more conducive for land cable applicationswhere transport limitations and extra splicing costs can driveup installation costs. The lower-cost cable installations madepossible by the extruded HVDC cables and prefabricatedjoints makes long-distance underground transmission eco-nomically feasible for use in areas with rights-of-way con-straints or subject to permitting difficulties or delays withoverhead lines.

Asynchronous TiesWith HVDC transmission systems, interconnections can bemade between asynchronous networks for more economic orreliable system operation. The asynchronous interconnectionallows interconnections of mutual benefit while providing abuffer between the two systems. Often these interconnectionsuse back-to-back converters with no transmission line.

37

figure 8. Solid-state converter development.

2,000

1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

1970

1973

1976

1979

1982

1985

1990

1993

1996

1999

2002

2005

2008

2011

Thyristor MW Thyristor KV IGBT MW IGBT kV

figure 9. HVDC IGBT valve converter arrangement.

IGBT Valve

StakPak

Submodule

Chip

Cable

Asynchronous HVDC links act as an effective “firewall”against propagation of cascading outages in one networkfrom passing to another network.

Many asynchronous interconnections exist in NorthAmerica between the Eastern and Western interconnectedsystems, between the Electric Reliability Council of Texas(ERCOT) and its neighbors, [e.g., Mexico and the SouthwestPower Pool (SPP)], and between Quebec and its neighbors(e.g., New England and the Maritimes). The August 2003

Northeast blackout provides an example of the “firewall”against cascading outages provided by asynchronous inter-connections. As the outage expanded and propagated aroundthe lower Great Lakes and through Ontario and New York, itstopped at the asynchronous interface with Quebec. Quebecwas unaffected; the weak ac interconnections between NewYork and New England tripped, but the HVDC links fromQuebec continued to deliver power to New England.

Regulators try to eliminate “seams” in electrical net-works because of their potential restrictionon power markets. Electrical “seams,”however, serve as natural points of separa-tion by acting as “shear-pins,” therebyreducing the impact of large-scale systemdisturbances. Asynchronous ties can elimi-nate market “seams” while retaining natu-ral points of separation.

Interconnections between asynchronousnetworks are often at the periphery of therespective systems where the networks tendto be weak relative to the desired powertransfer. Higher power transfers can beachieved with improved voltage stability inweak system applications using CCCs. Thedynamic voltage support and improved volt-age stability offered by VSC-based convert-ers permits even higher power transferswithout as much need for ac system rein-forcement. VSCs do not suffer commutationfailures, allowing fast recoveries from near-by ac faults. Economic power schedulesthat reverse power direction can be madewithout any restrictions since there is nominimum power or current restrictions.

Offshore TransmissionSelf-commutation, dynamic voltage control,and black-start capability allow compact VSCHVDC transmission to serve isolated loadson islands or offshore production platformsover long-distance submarine cables. Thiscapability can eliminate the need for runningexpensive local generation or provide an out-let for offshore generation such as that fromwind. The VSCs can operate at variable fre-quency to more efficiently drive large com-pressor or pumping loads using high-voltagemotors. Figure 11 shows the Troll A produc-tion platform in the North Sea where powerto drive compressors is delivered from shoreto reduce the higher carbon emissions andhigher O&M costs associated with less effi-cient platform-based generation.

Large remote wind generation arraysrequire a collector system, reactive power

figure 10. Operating range for voltage source converter HVDC transmission.


Reactive Power (p.u.)

Act

ive

Pow

er (

p.u.

)

P-Q Diagram

HVDC VSC Operating Range

1.25

1.25

1

10

0.75

0.75

0.5

0.5

0.25

0.25−1.25

−1.25

−0.75

−0.75

−0.5

−0.5

−0.25

−0.25

−1

−1

1.25

1.25

Operating Area

figure 11. VSC power supply to Troll A production platform.

2 x 40 MW VSC HVDC


support, and outlet transmission.Transmission for wind genera-tion must often traverse scenic orenvironmentally sensitive areasor bodies of water. Many of thebetter wind sites with highercapacity factors are located off-shore. VSC-based HVDC trans-mission allows efficient use oflong-distance land or submarinecables and provides reactive sup-port to the wind generation com-plex. Figure 12 shows a designfor an offshore converter stationdesigned to transmit power fromoffshore wind generation.

Multiterminal SystemsMost HVDC systems are forpoint-to-point transmission with aconverter station at each end. Theuse of intermediate taps is rare.Conventional HVDC transmissionuses voltage polarity reversal toreverse the power direction. Polar-ity reversal requires no specialswitching arrangement for a two-terminal system where both termi-nals reverse polarity by controlaction with no switching toreverse power direction. Specialdc-side switching arrangementsare needed for polarity reversal ina multiterminal system, however,where it may be desired to reversethe power direction at a tap whilemaintaining the same powerdirection on the remaining termi-nals. For a bipolar system this canbe done by connecting the con-verter to the opposite pole. VSCHVDC transmission, however,reverses power through reversal ofthe current direction rather thanvoltage polarity. Thus, power canbe reversed at an intermediate tapindependently of the main powerflow direction without switchingto reverse voltage polarity.

Power Delivery toLarge Urban AreasPower supply for large citiesdepends on local generation andpower import capability. Local

39

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generation is often older and less efficient than newer unitslocated remotely. Often, however, the older, less-efficientunits located near the city center must be dispatched out-of-merit because they must be run for voltage support or relia-bility due to inadequate transmission. Air quality regulationsmay limit the availability of these units. New transmissioninto large cities is difficult to site due to right-of-way limita-tions and land-use constraints.

Compact VSC-based underground transmission circuitscan be placed on existing dual-use rights-of-way to bring inpower as well as to provide voltage support, allowing amore economical power supply without compromising reli-ability. The receiving terminal acts like a virtual generatordelivering power and supplying voltage regulation anddynamic reactive power reserve. Stations are compact andhoused mainly indoors, making siting in urban areas some-what easier. Furthermore, the dynamic voltage supportoffered by the VSC can often increase the capability of theadjacent ac transmission.

System Configurations and Operating ModesFigure 13 shows the different common system configura-tions and operating modes used for HVDC transmission.Monopolar systems are the simplest and least expensivesystems for moderate power transfers since only two con-verters and one high-voltage insulated cable or line conduc-tor are required. Such systems have been used withlow-voltage electrode lines and sea electrodes to carry thereturn current in submarine cable crossings.

In some areas conditions are not conducive to monopolarearth or sea return. This could be the case in heavily congested


figure 13. HVDC configurations and operating modes.

Monopole, Ground Return

Monopole, Metallic Return

Monopole, Midpoint Grounded

Back-to-Back

Multiterminal

Bipole, Metallic Return

BipoleBipole, Series-Connected

Converters

figure 12. VSC converter for offshore wind generation.


areas, fresh water cable crossings, or areas with high earthresistivity. In such cases a metallic neutral- or low-voltagecable is used for the return path and the dc circuit uses a simplelocal ground connection for potential reference only. Back-to-back stations are used for interconnection of asynchronous net-works and use ac lines to connect on either side. In suchsystems power transfer is limited by the relative capacities ofthe adjacent ac systems at the point of connection.

As an economic alternative to a monopolar system withmetallic return, the midpoint of a 12-pulseconverter can be connected to earthdirectly or through an impedance and twohalf-voltage cables or line conductors canbe used. The converter is only operated in12-pulse mode so there is never any strayearth current.

VSC-based HVDC transmission isusually arranged with a single converterconnected pole-to-pole rather than pole-to-ground. The center point of the con-verter is connected to ground through ahigh impedance to provide a referencefor the dc voltage. Thus, half the convert-er dc voltage appears across the insula-tion on each of the two dc cables, onepositive the other negative.

The most common configuration formodern overhead HVDC transmissionlines is bipolar with a single 12-pulse

converter for each pole at each terminal. This gives two inde-pendent dc circuits each capable of half capacity. For normalbalanced operation there is no earth current. Monopolar earthreturn operation, often with overload capacity, can be usedduring outages of the opposite pole.

Earth return operation can be minimized during monopolaroutages by using the opposite pole line for metallic return viapole/converter bypass switches at each end. This requires ametallic-return transfer breaker in the ground electrode line at

41

figure 14. Monopolar HVDC converter station.

Shunt Capacitors

ac Switchyard

ac Line

dc Line

Valve Hall

Converter Transformers

dc Switchyard

Harmonic Filters

figure 15. VSC HVDC converter station.

ac Filters

PhaseReactors

IGBT ValveEnclosures

Coolers

one of the dc terminals to commutate the current from the rel-atively low resistance of the earth into that of the dc line con-ductor. Metallic return operation capability is provided formost dc transmission systems. This not only is effective dur-ing converter outages but also during line insulation failureswhere the remaining insulation strength is adequate to with-stand the low resistive voltage drop in the metallic return path.

For very-high-power HVDC transmission, especially at dcvoltages above ±500 kV (i.e., ±600 kV or ±800 kV), series-connected converters can be used to reduce the energyunavailability for individual converter outages or partial lineinsulation failure. By using two series-connected convertersper pole in a bipolar system, only one quarter of the transmis-sion capacity is lost for a converter outage or if the line insu-lation for the affected pole is degraded to where it can onlysupport half the rated dc line voltage. Operating in this modealso avoids the need to transfer to monopolar metallic returnto limit the duration of emergency earth return.

Station Design and Layout

Conventional HVDCThe converter station layout depends on a number of factorssuch as the dc system configuration (i.e., monopolar, bipolar,or back-to-back), ac filtering, and reactive power compensa-tion requirements. The thyristor valves are air-insulated,water-cooled, and enclosed in a converter building oftenreferred to as a valve hall. For back-to-back ties with theircharacteristically low dc voltage, thyristor valves can behoused in prefabricated electrical enclosures, in which case avalve hall is not required.

To obtain a more compact station design and reduce thenumber of insulated high-voltage wall bushings, convertertransformers are often placed adjacent to the valve hall withvalve winding bushings protruding through the building

walls for connection to the valves. Double or quadruplevalve structures housing valve modules are used within thevalve hall. Valve arresters are located immediately adjacentto the valves. Indoor motor-operated grounding switches areused for personnel safety during maintenance. Closed-loopvalve cooling systems are used to circulate the cooling medi-um, deionized water or water-glycol mix, through the indoorthyristor valves with heat transfer to dry coolers located out-doors. Area requirements for conventional HVDC converterstations are influenced by the ac system voltage and reactivepower compensation requirements where each individualbank rating may be limited by such system requirements asreactive power exchange and maximum voltage step on bankswitching. The ac yard with filters and shunt compensationcan take up as much as three quarters of the total arearequirements of the converter station. Figure 14 shows a typ-ical arrangement for an HVDC converter station.

VSC-Based HVDCThe transmission circuit consists of a bipolar two-wire HVDCsystem with converters connected pole-to-pole. DC capacitorsare used to provide a stiff dc voltage source. The dc capacitorsare grounded at their electrical center point to establish theearth reference potential for the transmission system. There isno earth return operation. The converters are coupled to the acsystem through ac phase reactors and power transformers.Unlike most conventional HVDC systems, harmonic filtersare located between the phase reactors and power transform-ers. Therefore, the transformers are exposed to no dc voltagestresses or harmonic loading, allowing use of ordinary powertransformers. Figure 15 shows the station arrangement for a±150-kV, 350 to 550-MW VSC converter station.

The IGBT valves used in VSC converters are comprised ofseries-connected IGBT positions. The IGBT is a hybrid deviceexhibiting the low forward drop of a bipolar transistor as a


figure 16. Conventional HVDC control.

uRuSuT

531

64 2

Id

Ud

IRISIT

acBus

acBus

Control

TCP TCP

dc Line

ID R

UdR Udl

Control

uT

uR

uS

uαIR

IS

αu

IT

∼∼∼


conducting device. Instead of the regular current-controlledbase, the IGBT has a voltage-controlled capacitive gate, as inthe MOSFET device.

A complete IGBT position consists of an IGBT, an anti-parallel diode, a gate unit, a voltage divider, and a water-cooled heat sink. Each gate unit includes gate-drivingcircuits, surveillance circuits, and optical interface. The gate-driving electronics control the gate voltage and current atturn-on and turn-off to achieve optimal turn-on and turn-offprocesses of the IGBTs.

To be able to switch voltages higher than the rated volt-age of one IGBT, many positions are connected in series ineach valve similar to thyristors in conventional HVDCvalves. All IGBTs must turn on and off at the same momentto achieve an evenly distributed voltage across the valve.Higher currents are handled by paralleling IGBT compo-nents or press packs.

The primary objective of the valve dc-side capacitor is toprovide a stiff voltage source and a low-inductance path forthe turn-off switching currents and to provide energy storage.The capacitor also reduces the harmonic ripple on the dc volt-age. Disturbances in the system (e.g., ac faults) will cause dcvoltage variations. The ability to limit these voltage variationsdepends on the size of the dc-side capacitor. Since the dccapacitors are used indoors, dry capacitors are used.

AC filters for VSC HVDC converters have smaller ratingsthan those for conventional converters and are not requiredfor reactive power compensation. Therefore, these filters are

always connected to the converter bus and not switched withtransmission loading. All equipment for VSC-based HVDCconverter stations, except the transformer, high-side breaker,and valve coolers, is located indoors.

HVDC Control and Operating Principles

Conventional HVDC The fundamental objectives of an HVDC control system areas follows:

1) to control basic system quantities such as dc line cur-rent, dc voltage, and transmitted power accurately andwith sufficient speed of response

2) to maintain adequate commutation margin in inverteroperation so that the valves can recover their forwardblocking capability after conduction before their volt-age polarity reverses

3) to control higher-level quantities such as frequency inisolated mode or provide power oscillation damping tohelp stabilize the ac network

4) to compensate for loss of a pole, a generator, or an actransmission circuit by rapid readjustment of power

5) to ensure stable operation with reliable commutation inthe presence of system disturbances

6) to minimize system losses and converter reactivepower consumption

7) to ensure proper operation with fast and stable recover-ies during ac system faults and disturbances.

43

figure 17. Control of VSC HVDC transmission.

Principle Control of HVDC-Light

uDC-ref1

uDC1

+

−

uAC1uAC-ref1

pref1

uDC-ref2

uDC2

+

−

uAC2 uAC-ref2

pref2 qref2

PWM PWMInternalCurrentControl

InternalCurrentControl

qref1

acVoltageControl

acVoltageControl

+

−i i

ac Line Voltages OPWM

dcVoltageControl

dcVoltageControl

For conventional HVDC transmission, one terminal setsthe dc voltage level while the other terminal(s) regulates the(its) dc current by controlling its output voltage relative tothat maintained by the voltage-setting terminal. Since the dcline resistance is low, large changes in current and hencepower can be made with relatively small changes in firingangle (alpha). Two independent methods exist for control-ling the converter dc output voltage. These are 1) by chang-ing the ratio between the direct voltage and the ac voltageby varying the delay angle or 2) by changing the converterac voltage via load tap changers (LTCs) on the convertertransformer. Whereas the former method is rapid the lattermethod is slow due to the limited speed of response of theLTC. Use of high delay angles to achieve a larger dynamicrange, however, increases the converter reactive power con-sumption. To minimize the reactive power demand whilestill providing adequate dynamic control range and commu-tation margin, the LTC is used at the rectifier terminal tokeep the delay angle within its desired steady-state range(e.g., 13–18◦) and at the inverter to keep the extinctionangle within its desired range (e.g., 17–20◦), if the angle isused for dc voltage control or to maintain rated dc voltage ifoperating in minimum commutation margin control mode.Figure 16 shows the characteristic transformer current anddc bridge voltage waveforms along with the controlleditems Ud, Id, and tap changer position (TCP).

VSC-Based HVDCPower can be controlled by changing the phase angle of theconverter ac voltage with respect to the filter bus voltage,whereas the reactive power can be controlled by changing themagnitude of the fundamental component of the converter acvoltage with respect to the filter bus voltage. By controllingthese two aspects of the converter voltage, operation in allfour quadrants is possible. This means that the converter canbe operated in the middle of its reactive power range nearunity power factor to maintain dynamic reactive powerreserve for contingency voltage support similar to a static varcompensator. It also means that the real power transfer canbe changed rapidly without altering the reactive powerexchange with the ac network or waiting for switching ofshunt compensation.

Being able to independently control ac voltage magnitudeand phase relative to the system voltage allows use of sepa-rate active and reactive power control loops for HVDC sys-tem regulation. The active power control loop can be set tocontrol either the active power or the dc-side voltage. In a dclink, one station will then be selected to control the activepower while the other must be set to control the dc-side volt-age. The reactive power control loop can be set to controleither the reactive power or the ac-side voltage. Either ofthese two modes can be selected independently at either endof the dc link. Figure 17 shows the characteristic ac voltagewaveforms before and after the ac filters along with the con-trolled items Ud, Id, Q, and Uac.

ConclusionsThe favorable economics of long-distance bulk-power trans-mission with HVDC together with its controllability make itan interesting alternative or complement to ac transmission.The higher voltage levels, mature technology, and new con-verter designs have significantly increased the interest inHVDC transmission and expanded the range of applications.

For Further ReadingB. Jacobson, Y. Jiang-Hafner, P. Rey, and G. Asplund,“HVDC with voltage source converters and extruded cablesfor up to ±300 kV and 1000 MW,” in Proc. CIGRÉ 2006,Paris, France, pp. B4–105.

L. Ronstrom, B.D. Railing, J.J. Miller, P. Steckley, G.Moreau, P. Bard, and J. Lindberg, “Cross sound cable projectsecond generation VSC technology for HVDC,” Proc.CIGRÉ 2006, Paris, France, pp. B4–102.

M. Bahrman, D. Dickinson, P. Fisher, and M. Stoltz,“The Rapid City Tie—New technology tames the East-Westinterconnection,” in Proc. Minnesota Power Systems Conf.,St. Paul, MN, Nov. 2004.

D. McCallum, G. Moreau, J. Primeau, D. Soulier, M.Bahrman, and B. Ekehov, “Multiterminal integration of theNicolet Converter Station into the Quebec-New EnglandPhase II transmission system,” in Proc. CIGRÉ 1994, Paris,France.

A. Ekstrom and G. Liss, “A refined HVDC control sys-tem,” IEEE Trans. Power Systems, vol. PAS-89, pp. 723–732,May-June 1970.

BiographiesMichael P. Bahrman received a B.S.E.E. from MichiganTechnological University. He is currently the U.S. HVDCmarketing and sales manger for ABB Inc. He has 24 years ofexperience with ABB Power Systems including systemanalysis, system design, multiterminal HVDC control devel-opment, and project management for various HVDC andFACTS projects in North America. Prior to joining ABB, hewas with Minnesota Power for 10 years where he held posi-tions as transmission planning engineer, HVDC control engi-neer, and manager of system operations. He has been anactive member of IEEE, serving on a number of subcommit-tees and working groups in the area of HVDC and FACTS.

Brian K. Johnson received the Ph.D. in electrical engi-neering from the University of Wisconsin-Madison. He iscurrently a professor in the Department of Electrical andComputer Engineering at the University of Idaho. Hisinterests include power system protection and the applica-tion of power electronics to utility systems, security andsurvivability of ITS systems and power systems, distrib-uted sensor and control networks, and real-time simulationof traffic systems. He is a member of the Board of Gover-nors of the IEEE Intelligent Transportation Systems Soci-ety and the Administrative Committee of the IEEECouncil on Superconductivity.


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