anexo g - material de apoyo para estimado de costos opción ... · 1. se asume que el costo total...

Pág. 128

ANEXO G - Material de Apoyo para Estimado de Costos Opción Línea AC

Tabla G1 – Desglose de Costos para nueva Línea de Transmisión Simple terna @ 220

kV

Base de Datos Propia 220 kV SIMPLE TERNA MATERIALES US $/km CONDUCTOR 12,000.00 TORRES 50,000.00 AISLADORES 12,000.00 HERRAJES 8,000.00 ESP. AMORTIGUADORES - CABLE DE GUARDA 4,000.00 HERRAJES CABLE DE GUARDA 1,000.00 PUESTA A TIERRA 13,000.00 TOTAL MATERIALES

COSTO MATERIAL (US $ equiv./km) 100,000.00

MONTAJE US $/km DEFORESTACION 9,000.00 CAMINO DE ACCESO 2,500.00 REVISION DE REPLANTEO 2,000.00 MONTAJE DE TORRES 30,000.00 TENDIDO DEL CONDUCTOR 3,000.00 MONTAJE DE CADENAS 2,000.00 TENDIDO DEL CABLE DE GUARDA 8,000.00 MONTAJE PUESTA A TIERRA 18,000.00 MONTAJE DE ESPACIADORES A. - MONTAJE DE HERRAJES C.D.G. 500.00 FUNDACIONES 33,333.33 TOTAL MONTAJE COSTO MONTAJE (US $ equiv./km) 108,333.33

Factor Terreno Montañoso 18% COSTO (MATERIAL + MONTAJE) 245,833.33

Imprevistos (10%) 24,583.33

COSTO TOTAL UNITARIO 295,000.00

Distancia (km) 600

COSTO TOTAL 177,000,000.00

Solo Línea AC Costo de Equipamiento 70,800,000.00 Obras de Montaje 53,100,000.00 Obras Civiles 23,600,000.00 Otros 29,500,000.00 TOTAL 177,000,000.01

Extensión S/E Celdas 4,000,000.00

TOTAL Costo de Equipamiento 74,800,000.00 Obras de Montaje 53,100,000.00 Obras Civiles 23,600,000.00 Otros 29,500,000.00 TOTAL 181,000,000.01

Se asumieron costos asociados a terreno montañoso (caso de la Sierra), lo que se muestra como factor terreno montañoso. Así mismo, se asumió una extensión en las subestaciones asociadas con la línea en 220 kV. El costo unitario equivalente es de kUS$ 295/km, lo cual está en un rango intermedio de diferentes alternativas conocidas para diferentes países, como se muestra en la tabla C2. Esto sirve de benchmarking y verificación para el costo total anterior de US$ 181.00 millones. A este costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW.

Tabla G2 – Costos Unitarios Representativos

País Costo

Unitario [kUS$/km]

Eficiente 180 Sudáfrica 225 Venezuela 250 Kenya 260 Perú 295 Uganda 375

Notas: 1.- El esquema mostrado como costo eficiente se basa en el mínimo costo asociado a procesos competitivos, asumiendo mínimo retorno en la inversión (fijado por el Regulador) y mínima infraestructura para prestar servicio con calidad requerida por el regulador. 2.- Para el caso de Perú se promediaron dos proyectos similares en 220 kV, como lo son las líneas Cajamarca-Caclic-Moyobamba y Cotaruse-Machu Picchu (ver Anexo 7.6 del Plan Referencial de Electricidad 2006-2015 del Ministerio de Energía y Minas). Con relación a plazos de proyectos similares, se estima una duración promedio de 30 km/mes (basado en buen tiempo asociado durante ese periodo). Esto se traduce para 600 km en un total estimado de 20 meses de duración. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW.

Pág. 129

ANEXO H - Material de Apoyo para Estimado de Costos Opción HVDC

Tabla H1 – Desglose de Costos para nueva Línea de Transmisión HVDC convencional @ ±250 kV

±250 kV DC

Equipo Terminal HVDC 120,000,000

Equipo Línea HVDC 42,480,000

Costo Total Equipos 162,480,000

Costo de Equipamiento 162,480,000

Obras de Montaje 8,496,000

Obras Civiles 6,372,000

Otros 5,734,800

TOTAL 183,082,800

Los costos desglosados en la tabla E1 arriba corresponden con la opción B1 (nueva línea HVDC convencional de ≈600 MW / ≈600 km Mantaro – Socabaya). La tabla anterior asume que el costo de equipos de la línea en HVDC no supera el 60% del costo de equipos de la línea HVAC. Por otra parte, el costo de la opción B2 (nueva línea HVDC “Convertidor de Fuente de Tensión” de ≈600 MW / ≈600 km Mantaro – Socabaya) se asume similar a la B1, basado en los siguientes supuestos: 1. Se asume que el costo total del Terminal HVDC es aproximadamente igual al de la

opción B1. 2. Se asume que el hecho de que el costo de los convertidoras de fuente de tensión

sea mayor que los convertidoras “estándar” o convencionales es compensado por costos significativamente menores en el patio AC (no se requieren capacitores shunt ni SVCs) y menos requerimiento de espacio.

3. Se asume que el costo de la línea HVDC es similar a la opción B1. La construcción de las líneas HVDC coincidiría aproximadamente con las AC, es decir unos 20 meses. Sin embargo, generalmente el cuello de botella en estos proyectos viene dado por las estaciones convertidoras. La duración promedio de estaciones similares a las asociadas con este proyecto (tanto las convencionales como las del tipo VSC) demoraría entre 24 y 30 meses, dependiendo de las particularidades finales de diseño, desde el otorgamiento de la buena pro hasta el arranque. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW.

Tabla H2 – Desglose de Costos para nuevo Convertidor HVDC Back-to-Back de 300-600 MW instalado en la S/E Cotaruse @ ±250 kV

±250 kV

Equipo Terminal HVDC 120,000,000.00

Equipo Línea HVDC -

Costo Total Equipos 120,000,000.00

Costo de Equipamiento 120,000,000.00

Obras de Montaje 5,310,000.00

Obras Civiles 2,360,000.00

Otros 2,330,000.00

TOTAL 130,000,000.00

Finalmente, el costo de la opción C (nuevo convertidor HVDC Back-to-Back de 600 MW instalado en la S/E Cotaruse) asume lo siguiente: 1. Se asume que el costo total del Terminal HVDC es aproximadamente similar al de

las opciones B1 y B2 (basado en nuestro Dpto. de HVDC). 2. Se asume que no hay costo de línea HVDC en esta opción. El artículo incluido a continuación muestra información de costos reciente publicada en IEEE. El documento que se encuentra a continuación del artículo del IEEE, es un documento público de Oak Ridge Nacional Laboratory titulado “HVDC Power Transmission Technology Assessment” en el cual colaboró personal de Siemens PTI (conocida simplemente como PTI a la fecha). Dicha entidad pertenece a la Secretaría de Energía del gobierno de los EEUU. La página 67 de dicho documento incluye un costo de US$/kW/Terminal de 100, el cual fue usado para estimar el costo de cada Terminal HVDC de las opciones B1 y B2. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW. La duración promedio de estaciones B2B (Back-to-Back) similares a las asociadas con este proyecto demoraría entre 24 y 30 meses, dependiendo de las particularidades finales de diseño, desde el otorgamiento de la buena pro hasta el arranque.

march/april 2007 IEEE power & energy magazine 33

H

©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.

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++

+

+

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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.

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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

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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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Pág. 130

ANEXO I - Material de Apoyo para Estimado de Costos Opciones E, F y G

Tabla I1 – Desglose de Costos para nuevo equipo TCSC en la S/E Cotaruse

TCSC 150 MVAr

US$/kVAr 70


Obras de Montaje 850,000


Otros 1,050,000

TOTAL 13,650,000

El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 6 (o Exhibit 5) muestra rangos de costos unitarios en US$/kVAr para TCSC. Considerando una capacidad de 150 MVAr es posible determinar de dicha figura que el rango de costos podría oscilar entre 60 y 80 US$/kVAr. Consecuentemente, utilizamos el valor medio de 70 US$/kVAr para obtener un costo de equipos de US$ 10.5 millones y un costo total de US$ 13.65 millones. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW. Proyectos nuevos de TCSC pueden demorar entre 24 y 30 meses, incluyendo estudio, diseño, pruebas y arranque.

Tabla I2 – Desglose de Costos para incrementar la compensación serie existente a 600 MW

Compensación Serie 150 MVAr

US$/kVAr 30



Obras Civiles 550,000

Otros 450,000

TOTAL 5,850,000

El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 6 (o

Exhibit 5) muestra rangos de costos unitarios en US$/kVAr para compensación serie (FSC). Considerando una capacidad de 150 MVAr es posible determinar de dicha figura que el rango de costos podría oscilar entre 20 y 40 US$/kVAr. Consecuentemente, utilizamos el valor medio de 30 US$/kVAr para obtener un costo de equipos de US$ 4.5 millones y un costo total de US$ 5.85 millones. Proyectos de compensación serie similares pueden tomar un plazo de 3 a 9 meses, dependiendo de las particularidades del proyecto.

Tabla I3 – Desglose de Costos para nuevo equipo SVC en la S/E Cotaruse

SVC 150 MVAr

US$/kVAr 65.00




Otros 975,000

TOTAL 12,675,000

El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 5 (o Exhibit 5) muestra rangos de costos unitarios en US$/kVAr para SVC’s. Considerando una capacidad de 150 MVAr es posible determinar de dicha figura que el rango de costos podría oscilar entre 50 y 80 US$/kVAr. Consecuentemente, utilizamos el valor medio de 65 US$/kVAr para obtener un costo de equipos de US$ 9.75 millones y un costo total aproximado de US$ 12.68 millones. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW. Proyectos similares de SVC pueden ser diseñados y producidos en unos 10 a 12 meses. Transporte, instalación, pruebas y arranque se puede demorar entre 4 y 6 meses. En total, el proyecto necesita un plazo entre 14 a 18 meses. Es importante destacar de nuevo que los estimados de costos realizados en todo el presente informe tendrían una precisión aproximada (rango) de ±30%.

Tabla I4 – Desglose de Costos para nueva Línea de Transmisión AC @ 500 kV

Base de Datos Propia 500 kV SIMPLE TERNA MATERIALES US $/km

CONDUCTOR 23,000.00


TORRES 65,000.00

AISLADORES 13,000.00

HERRAJES 8,000.00

ESP. AMORTIGUADORES 4,000.00

CABLE DE GUARDA 4,000.00

HERRAJES CABLE DE GUARDA 1,000.00

PUESTA A TIERRA 12,500.00

TOTAL MATERIALES

COSTO MATERIAL (US $ equiv./km) 130,500.00

MONTAJE US $/km

DEFORESTACION 18,000.00

CAMINO DE ACCESO 2,250.00

REVISION DE REPLANTEO 1,500.00

MONTAJE DE TORRES 30,000.00

TENDIDO DEL CONDUCTOR 6,000.00

MONTAJE DE CADENAS 2,000.00

TENDIDO DEL CABLE DE GUARDA 7,750.00

MONTAJE PUESTA A TIERRA 17,000.00

MONTAJE DE ESPACIADORES A. 3,000.00

MONTAJE DE HERRAJES C.D.G. 500.00

FUNDACIONES 35,000.00

TOTAL MONTAJE

COSTO MONTAJE (US $ equiv./km) 123,000.00

Factor Terreno Montañoso 18%

COSTO (MATERIAL + MONTAJE) 299,130.00


Imprevistos (20%) 59,826.00

COSTO TOTAL UNITARIO 358,956.00

Distancia (km) 815

COSTO TOTAL 292,549,140.00

Solo Línea AC




Otros 48,758,190.00

TOTAL 292,549,140.00

Extensión S/E

Celdas 8,000,000.00

TOTAL




Otros 48,758,190.00

TOTAL 300,549,140.00

Se asumieron costos asociados a terreno montañoso (caso de la costa), lo que se muestra como factor terreno montañoso. Así mismo, se asumió una extensión en las subestaciones asociadas con la línea en 500 kV. El costo unitario equivalente es de casi kUS$ 360/km, al cual debe incluirse el incremento por la compensación serie adicional, hasta 505 MW.

Tabla I5 – Desglose de Costos para equipo Phase Shifter en línea de 500 kV AC

Phase Shifter 600 MVAr

US$/kVAr 15.00




Otros 900,000

TOTAL 11,700,000

El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 6 (o Exhibit 6) muestra rangos de costos unitarios en US$/kVAr para FSC’s. Considerando una capacidad de 600 MVAr es posible determinar de dicha figura que el rango de costos podría oscilar alrededor de 15 US$/kVAr para obtener un costo de equipos de US$ 9 millones y un costo total aproximado de US$ 11.7 millones. El costo debe incluirse el incremento por la compensación serie adicional, hasta 505 MW. Proyectos similares de Phase Shifter no tienen mayor impacto dentro de la construcción de una línea en 500 kV. Es importante destacar de nuevo que los estimados de costos realizados en todo el presente informe tendrían una precisión aproximada (rango) de ±30%.

of 11

FACTS – Flexible Alternating Current Transmission Systems

For Cost Effective and Reliable Transmission of Electrical Energy

Klaus Habur and Donal O’Leary (1)

Flexible alternating current transmissionsystems (FACTS) devices are used for thedynamic control of voltage, impedance andphase angle of high voltage AC lines. FACTSdevices provide strategic benefits forimproved transmission system managementthrough: better utilization of existingtransmission assets; increased transmissionsystem reliability and availability; increaseddynamic and transient grid stability;increased quality of supply for sensitiveindustries (e.g. computer chip manufacture);and enabling environmental benefits.Typically the construction period for a factsdevice is 12 to 18 months from contractsigning through commissioning. This paperstarts by providing definitions of the mostcommon application of FACTS devices aswell as enumerates their benefits (focussingon steady state and dynamic applications).Generic information on the costs andbenefits of FACTS devices is then providedas well as the steps for identification ofFACTS projects. The paper then discussesseven applications of FACTS devices inAustralia, Brazil, Indonesia, South Africa andthe USA. The paper concludes with somerecommendations on how the World Bankcould facilitate the increased usage ofFACTS.

Introduction

The need for more efficient electricity systemsmanagement has given rise to innovativetechnologies in power generation andtransmission. The combined cycle power stationis a good example of a new development inpower generation and flexible AC transmissionsystems, FACTS as they are generally known,are new devices that improve transmissionsystems.

Worldwide transmission systems are undergoingcontinuous changes and restructuring. They are

becoming more heavily loaded and are beingoperated in ways not originally envisioned.Transmission systems must be flexible to reactto more diverse generation and load patterns. Inaddition, the economical utilization oftransmission system assets is of vitalimportance to enable utilities in industrializedcountries to remain competitive and to survive.In developing countries, the optimized use oftransmission systems investments is alsoimportant to support industry, createemployment and utilize efficiently scarceeconomic resources.

Flexible AC Transmission Systems (FACTS) is atechnology that responds to these needs. Itsignificantly alters the way transmissionsystems are developed and controlled togetherwith improvements in asset utilization, systemflexibility and system performance.

What are FACTS devices?

FACTS devices are used for the dynamic controlof voltage, impedance and phase angle of highvoltage AC transmission lines. Below thedifferent main types of FACTS devices aredescribed:

Static Var Compensators (SVC’s), the mostimportant FACTS devices, have been used for anumber of years to improve transmission lineeconomics by resolving dynamic voltageproblems. The accuracy, availability and fastresponse enable SVC’s to provide highperformance steady state and transient voltagecontrol compared with classical shuntcompensation. SVC’s are also used to dampenpower swings, improve transient stability, andreduce system losses by optimized reactivepower control.

Thyristor controlled series compensators(TCSCs) are an extension of conventional seriescapacitors through adding a thyristor-controlledreactor. Placing a controlled reactor in parallel

FACTS – For cost effective and reliable transmission of electrical energy

Page 2 of 11

with a series capacitor enables a continuous andrapidly variable series compensation system.The main benefits of TCSCs are increasedenergy transfer, dampening of poweroscillations, dampening of subsynchronousresonances, and control of line power flow.

STATCOMs are GTO (gate turn-off typethyristor) based SVC’s. Compared withconventional SVC’s (see above) they don’trequire large inductive and capacitivecomponents to provide inductive or capacitivereactive power to high voltage transmissionsystems. This results in smaller landrequirements. An additional advantage is thehigher reactive output at low system voltageswhere a STATCOM can be considered as acurrent source independent from the systemvoltage. STATCOMs have been in operation forapproximately 5 years.

Unified Power Flow Controller (UPFC).Connecting a STATCOM, which is a shuntconnected device, with a series branch in thetransmission line via its DC circuit results in aUPFC. This device is comparable to a phaseshifting transformer but can apply a seriesvoltage of the required phase angle instead of avoltage with a fixed phase angle. The UPFCcombines the benefits of a STATCOM and aTCSC.

Exhibit 1: UPFC circuit diagram

The section on Worldwide Applications containsdescriptions of typical applications for FACTSdevices.

Benefits of utilizing FACTS devicesThe benefits of utilizing FACTS devices inelectrical transmission systems can besummarized as follows:

• Better utilization of existing transmissionsystem assets

• Increased transmission system reliabilityand availability

• Increased dynamic and transient gridstability and reduction of loop flows

• Increased quality of supply for sensitiveindustries

• Environmental benefits

Better utilization of existing transmissionsystem assetsIn many countries, increasing the energytransfer capacity and controlling the load flow oftransmission lines are of vital importance,especially in de-regulated markets, where thelocations of generation and the bulk load centerscan change rapidly. Frequently, adding newtransmission lines to meet increasing electricitydemand is limited by economical andenvironmental constraints. FACTS devices helpto meet these requirements with the existingtransmission systems.

Increased transmission system reliabilityand availabilityTransmission system reliability and availability isaffected by many different factors. AlthoughFACTS devices cannot prevent faults, they canmitigate the effects of faults and make electricitysupply more secure by reducing the number ofline trips. For example, a major load rejectionresults in an over voltage of the line which canlead to a line trip. SVC’s or STATCOMscounteract the over voltage and avoid linetripping.

Increased dynamic and transient gridstabilityLong transmission lines, interconnected grids,impacts of changing loads and line faults cancreate instabilities in transmission systems.These can lead to reduced line power flow, loopflows or even to line trips. FACTS devicesstabilize transmission systems with resulting


Page 3 of 11

higher energy transfer capability and reducedrisk of line trips.

Increased quality of supply for sensitiveindustriesModern industries depend upon high qualityelectricity supply including constant voltage, andfrequency and no supply interruptions. Voltagedips, frequency variations or the loss of supplycan lead to interruptions in manufacturingprocesses with high resulting economic losses.FACTS devices can help provide the requiredquality of supply.

Environmental benefitsFACTS devices are environmentally friendly.They contain no hazardous materials andproduce no waste or pollutanse. FACTS helpdistribute the electrical energy moreeconomically through better utilization of existinginstallations thereby reducing the need foradditional transmission lines.

Applications and technical benefits of FACTS devices

Exhibits 2 to 4 below describe the technicalbenefits of the principal FACTS devicesincluding steady state applications in addressingproblems of voltage limits, thermal limits, loopflows, short circuit levels and subsynchronousresonance. For each problem the conventionalsolution (e.g. shunt reactor or shunt capacitor) isalso provided (as well as for dynamicapplications – see below), as well as dynamicapplications of FACTS in addressing problemsin transient stability, dampening, postcontingency voltage control and voltage stability.FACTS devices are required when there is aneed to respond to dynamic (fast-changing)network conditions. The conventional solutions

are normally less expensive than FACTSdevices – but limited in their dynamic behavior. Itis the task of the planners to identify the mosteconomic solution.In Exhibits 3 and 4 information is provided onFACTS devices with extensive operationalexperience and widespread use such as SVC,STATCOM, TCSC and UPFC. In addition,information is provided on FACTS devices thatare either under discussion, development or asprototype in operation such as the thyristorcontrolled phase-angle regulator (TCPAR); thethyristor controlled voltage limiter (TCVL); andthe thyristor switched series capacitor (TCSC).

Technical benefits of the main FACTS devices

Exhibit 2: Benefits of FACTS devices for different applications

Better


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Steady state applications of FACTS

Issue Problem Corrective Action Conventional solution FACTS deviceLow voltage at heavyload

Supply reactive power Shunt capacitor, Seriescapacitor

SVC, TCSC, STATCOM

Remove reactive powersupply

Switch EHV line and/orshunt capacitor

SVC, TCSC, STATCOMHigh voltage at light load

Absorb reactive power Switch shunt capacitor,shunt reactor

SVC, STATCOM

Absorb reactive power Add shunt reactor SVC, STATCOMHigh voltage followingoutage Protect equipment Add arrestor SVC

Supply reactive power Switch shunt capacitor,reactor, series capacitor

SVC, STATCOMLow voltage followingoutage

Prevent overload Series reactor, PAR TCPAR, TCSC

Voltage limits

Low voltage andoverload

Supply reactive powerand limit overload

Combination of two ormore devices

TCSC, UPFC,STATCOM, SVC

Add line or transformer TCSC, UPFC, TCPARLine or transformeroverload

Reduce overloadAdd series reactor SVC, TCSC

Thermal limits

Tripping of parallelcircuit (line)

Limit circuit (line)loading

Add series reactor,capacitor

UPFC, TCSC

Adjust series reactance Add seriescapacitor/reactor

UPFC, TCSCParallel line load sharing

Adjust phase angle Add PAR TCPAR, UPFCPost-fault sharing Rearrange network or

use “Thermal limit”actions

PAR, SeriesCapacitor/Reactor

TCSC, UPFC, SVC,TCPAR

Loop flows

Flow direction reversal Adjust phase angle PAR TCPAR, UPFCLimit short circuit current Add series reactor, new

circuit breakerSCCL, UPFC, TCSC

Change circuit breaker Add new circuit breaker

Short circuit levels Excessive breaker faultcurrent

Rearrange network Split busSubsynchronousresonance

Potential turbine/generator shaft damage

Mitigate oscillations series compensation NGH, TCSC

Legend for Exhibit 3NGH = Hingorani Damper TCSC = Thyristor Controlled Series CapacitorPAR = Phase-Angle-Regulator TCVL = Thyristor Controlled Voltage LimiterSCCL = Super-Conducting Current Limiter TSBR = Thyristor Switched Braking ResistorSVC = Static Var Compensator TSSC = Thyristor Switched Series CapacitorSTATCOM = Static Compensator UPFC = Unified Power Flow ControllerTCPAR = Thyristor Controlled Phase-Angle Regulator

Exhibit 3: Steady state applications of FACTS

FACTS are a well-proven technology.The first installations were put into service over20 years ago. As of January 2000, the totalworldwide installed capacity of FACTS devicesis more than 40,000 MVAr in several hundredinstallations. While FACTS devices are usedprimarily in the electricity supply industry, they

are also used in computer hardware and steelmanufacturing (SVC’s for flicker compensation),as well as for voltage control in transmissionsystems for railways and in research centers(e.g. CERN in Geneva).


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Dynamic applications of FACTS

Issue Type of System Corrective Action Conventional Solution FACTS deviceA, B, D Increase synchronizing

torqueHigh-response exciter,series capacitor

TCSC, TSSC, UPFC

A, D Absorb kinetic energy Braking resistor, fastvalving (turbine)

TCBR, SMES, BESS

Transient Stability

B, C, D Dynamic load flowcontrol

HVDC TCPAR, UPFC, TCSC

A Dampen 1 Hzoscillations

Exciter, Power systemstabilizer (PSS),

SVC, TCSC, STATCOMDampening

B, D Dampen low frequencyoscillations

- Power systemstabilizer (PSS)

SVC, TCPAR, UPFC,NGH, TCSC, STATCOM

Dynamic voltagesupport

- SVC, STATCOM,UPFC,

Dynamic flow control - SVC, UPFC, TCPAR

A, B, D

Dynamic voltagesupport and flow control

- SVC, UPFC, TCSC

Post ContingencyVoltage Control

A, B, C, D Reduce impact ofcontingency

parallel lines SVC, TCSC,STATCOM, , UPFC

Reactive Support shunt capacitor, shuntreactor

SVC, STATCOM, UPFC

Network control actions LTC, reclosing, HVDCcontrols

UPFC, TCSC,STATCOM

Generation control High-response exciter -

Voltage Stability B, C, D

Load control Under-voltage loadsheddingDemand-SideManagement Programs

-

Legend for Exhibit 4:A. Remote Generation – Radial Lines (e.g. Namibia) B. Interconnected Areas (e.g. Brazil)C. Tightly meshed network (e.g. Western Europe) D. Loosely meshed network (e.g. Queensland, Austr.)

BESS = Battery Energy Storage System STATCOM = Static Synchronous CompensatorHVDC = High Voltage Direct CurrentLTC = Transformer-Load Tap Changer SVC = Static Var CompensatorNGH = Hingorani Damper TCPAR = Thyristor Controlled Phase-Angle RegulatorPAR = Phase-Angle Regulator TCSC = Thyristor Controlled Series CapacitorSCCL = Super-Conducting Current Limiter TCVL = Thyristor Controlled Voltage LimiterSMES = Super-Conducting Magnetic TSBR = Thyristor Switched Braking Resistor

Energy Storage TSSC = Thyristor Switched Series CapacitorUPFC = Unified Power Flow Controller

Exhibit 4: Dynamic applications of FACTS

Investment costs of FACTS devices.The investment costs of FACTS devices can bebroken down into two categories:(a) the devices’ equipment costs, and (b) thenecessary infrastructure costs.

Equipment costsEquipment costs depend not only upon theinstallation rating but also upon specialrequirements such as:

• redundancy of the control and protectionsystem or even main components such asreactors, capacitors or transformers,

• seismic conditions,• ambient conditions (e.g. temperature,

pollution level): and• communication with the Substation Control

System or the Regional or National ControlCenter.


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Infrastructure CostsInfrastructure costs depend on the substationlocation, where the FACTS device should beinstalled. These costs include e.g.• land acquisition, if there is insufficient space

in the existing substation,• modifications in the existing substation, e.g.

if new HV switchgear is required,• construction of a building for the indoor

equipment (control, protection, thyristorvalves, auxiliaries etc.),

• yard civil works (grading, drainage,foundations etc.), and

• connection of the existing communication

system with the new installation.

Exhibit 5: Typical investment costs for SVC / Statcom

For typical devices’ ratings, the lower limit of thecost areas shown in Exhibits 5 and 6 indicatesthe equipment costs, and the upper limitindicates the total investment costs including theinfrastructure costs. For very low ratings, costscan be higher and for very high power ratingscosts can be lower than indicated. The totalinvestment costs shown, which are exclusive oftaxes and duties, may vary due to the describedfactors by –10% to +30%. Including taxes andduties, which differ significantly betweendifferent countries, the total investment costs forFACTS devices may vary even more.

Exhibit 6: Typical investment cost for SC, TCSC andUPFC

What are the financial benefits ofFACTS devices?There are three areas were the financial benefitscould be calculated relatively easily.1. Additional sales due to increased

transmission capability.2. Additional wheeling charges due to

increased transmission capability.3. Avoiding or delaying of investments in

new high voltage transmission lines or evennew power generation.

Exhibit 7 gives indicates the possible additionalsales in US$ per year based on different energy Exhibit 7: Overview yearly sales

Length of Line in km100 200 300 400 500

M ill. US$

20

40

60

80

100

120

140

160

500 kV

345 kV

220 kV

132 kV

Source: Siemens AG Database

US$/kVAr

Operating Range in MVAr100 200 300 400 500

20

40

60

80

100

120

140

160

SVC

STATCOM


US$/kVAr

O p e r a t in g R a n g e in M V A r100 200 300 400 500

20

40

60

80

100

120

140

160

UPFC

TCSC

FSC



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costs / prices when a transmission line capacitycan be increased.

Exhibit 8 below gives some indication of typicalinvestment costs for new high voltage ACtransmission lines.

Exhibit 8: Typical costs of new AC transmission lines

Example 1:If through using a FACTS device, a fully loadedtransmission line’s capability could be increasedby 50 MW (e.g. for transmission lines of 132 kVor higher), this could generate additional sales of50 MW equivalent. Assuming a 100% load factorand a sales price of 0.02 US$ per kWh, thiswould result in additional annual electricitysales of up to US$ 8.8 million.

Example 2:Assume that the investment costs of a 300 kmlong 400 kV line are approx. US$. 45 million. Atan interest rate of 10%, this results in annualinterest costs of US$ 4,5 million. Installation of aFACTS device for e.g. US$ 20 million could beeconomically justified, if such an investment canbe avoided or delayed by at least 5 years (5times 4,5 = 22.5).

The above examples are only rough calculationsto indicate the possible direct economicalbenefits of FACTS devices.

There are also indirect benefits of utilizingFACTS devices, which are more difficult tocalculate. These include avoidance of industries’outage costs due to interruption of productionprocesses (e.g. paper industry, textile industry,

production of semi-conductors / computer chips)or load shedding during peak load times.

Maintenance of FACTS devicesMaintenance of FACTS devices is minimal andsimilar to that required for shunt capacitors,reactors and transformers. It can be performedby normal substation personnel with no specialprocedures. The amount of maintenance rangesfrom 150 to 250 man-hours per year anddepends upon the size of the installation and thelocal ambient (pollution) conditions.

Operation of FACTS devicesFACTS devices are normally operatedautomatically. They can be located in unmannedsubstations. Changing of set-points or operationmodes can be done locally and remotely (e.g.from a substation control room, a regionalcontrol centre, or a national control centre).

Steps for the Identification of FACTSProjects1. The first step should always be to conduct adetailed network study to investigate the criticalconditions of a grid or grids’ connections . Theseconditions could include: risks of voltageproblems or even voltage collapse, undesiredpower flows, as well as the potential for powerswings or subsynchronous resonances.2. For a stable grid, the optimized utilization ofthe transmission lines – e.g. increasing theenergy transfer capability – could beinvestigated.3. If there is a potential for improving thetransmission system, either through enhancedstability or energy transfer capability, theappropriate FACTS device and its requiredrating can be determined.4. Based on this technical information, aneconomical study can be performed to comparecosts of FACTS devices or conventionalsolutions with the achievable benefits.

Performance VerificationThe design of all FACTS devices should betested in a transient network analyzer (TNA)under all possible operational conditions andfault scenarios. The results of the TNA testsshould be consistent with the results of thenetwork study, which was performed at the startof the project. The results of the TNA study also

50 100 150 200 250 MW

120

80

40

60

100

20

140

160

Additional transmission capacity of a line

Add

ition

al s

ales

in M

ill. U

S$

0,06

0,04

0,02

0,01

US

$ pe

r kW

h



Page 8 of 11

provide the criteria for the evaluation of the sitecommissioning tests.

The consistency of the results• of the network study in the beginning of the

project,• of the TNA study with the actual parameters

and functions of the installation before goingto site and

• of the commissioning tests on siteensures the required functionality of the FACTSdevices.

Worldwide ApplicationsSeven projects are described below, whereFACTS devices have proven their benefits overseveral years. These descriptions also indicatehow the FACTS devices were designed to meetthe different requirements of the seventransmission systems. The investment costs forthese devices are consistent with the informationpresented in Exhibits 4 and 5 above.The construction period for a FACTS device istypically 12 to 18 months from contract signingthrough commissioning. Installations with a highdegree of complexity,, comprehensive approvalprocedures, and time-consuming equipmenttests may have longer construction periods.

The Australian InterconnectorThe interconnection of the South Australian,Victoria and New South Wales Systems involvedtransmission at voltages up to 500 kV overdistances exceeding 2200 km. Theinterconnection is for interchange of 500 MW.Two identical – 100 MVAr (inductive) /+ 150MVAr (capacitive) SVC’s at Kemps Creekimprove transient stability. Here each SVCconsists of two thyristor-switched capacitors anda thyristor-switched reactor that can be switchedin combination to provide uniform steps acrossthe full control range.

To ensure reliable operation under all powersystem conditions, the implementation of theSVC design had to be carefully evaluated priorto installation. The behavior of the SVC wasexamined at a transient network analyzer undera wide range of system conditions.

The three-state interconnected system and thetwo SVC’s were successfully put intocommercial operation in spring 1990. The twoSVC’s are equipped only with thyristor-switchedreactors and capacitors with the advantage that

no harmonics are generated and therefor nofilters are necessary.The system operates as expected and provedthe original concepts. As part of theinterconnected system, the compensators atKemps Creek have been called upon on severaloccasions to support the system and have doneso in an exemplary manner.

SOUTH AFRICA: Increase in Line Capacitywith SVCThe Kwazulu-Natal system of the Eskom Grid,South Africa, serves two major load centers(Durban and Richards Bay) at the extremities ofthe system. In 1993, the system was loadedclose to its voltage stability limit, a situationaggravated by the lack of base load generationcapacity in the area. The 1000 MW Drakensbergpumped storage scheme, by the nature of itsduty cycle and location remote from the mainload centers, does not provide adequatecapacity.

Exhibit 9: SOUTH AFRICA: SVC, Illovo.

The installation of three SVCs in the major loadcenters provides superior voltage controlperformance compared to an additional new linesubject to load switching.A further motivation for choosing SVCs in thiscase are their lower capital cost, reducedenvironmental impact, and the minimization offault-induced voltage reductions compared tobuilding additional transmission lines. Fault-induced voltage reductions cause majordisruption of industrial processes, and mainlyresult from transmission line faults. Thefrequency of such reductions is proportional tothe total line length exposed to the failuremechanisms (viz. sugar cane fires), resulting in


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a desire to minimize the total length oftransmission lines. These SVCs went intocommercial operation in 1995.

BRAZIL: North – South InterconnectionIn Brazil there are two independent transmissiongrids, the North grid and the South grid. Thesetwo grids cover more than 95% of the electricpower transmission in the country.Detailed studies demonstrated the economicattractiveness of connecting the two grids. Interalia they compared the attractiveness of buildingan AC or a HVDC (High Voltage Direct Current)connection of more than 1.000 km long passingthrough an area with a fast growing economyand also with a high hydropower potential. As itis technically much easier and more economicalto build new connections to an AC line than toan HVDC line it was decided to build a new ACline.

Exhibit 10: BRAZIL: TCSC, Serra de Mesa

The line, which is now in operation sincebeginning of 1999, is equipped with SC’s (SeriesCapacitors) and TCSC’s (Controlled SeriesCapacitors) to reduce the transmission lossesand to stabilize the line.

Initial studies indicated the potential for lowfrequency power oscillations between the twogrids which TCSC’s can dampen and therebymitigate the risk of line instability. In addition, theapplication of TCSCs can effectively reduce therisk of subsynchronous resonances (SSRs)caused by the application of SC’s in a line.SSRs in a transmission system are resonancephenomena between the electrical system andthe mechanical system of turbine – generator

shafts in thermal power stations. Under certainconditions SSRs can damage the shaft of theturbine – generator unit, which results in highrepair costs and lost generation during the unitrepair time.

USA: More Effective Long-Distance HVDC-SystemA major addition to the 500 kV transmissionsystem between Arizona and California, USA,was installed to increase power transfer. Thisaddition includes two new series - compensated500 kV lines and two large SVC’s. These SVC’sare needed to provide system security, safe andsecure power transmission, and support thenearby HVDC station of the Los AngelesDepartment of Water and Power (LADWP). Byinstalling the SVCs, the LADWP ensured itscapability to supply high quality electric power toist major customers and to minimize the risk ofsupply interruptions.

The control design for these SVC’s, based ondetailed analysis, is driven by the unique systemrequirement of dampening the complexoscillation modes between Arizona andCalifornia. Extensive testing on a real-timesimulator was done, including the HVDC systemoriginally delivered by another manufacturerbefore the controls were delivered on site. Fieldtests during and after commissioning verifiedthese results. These SVC’s, ones of the largestinstallations ever delivered, went intocommercial operation early 1996.

INDONESIA: Containerized DesignLoad flow and stability studies of the Indonesianpower system identified the need for a SVC witha control range of – 25 MVAr to + 50 MVAr atJember Substation(Bali). The SVC provides fastvoltage control to allow enhanced power transferunder extreme system contingencies, i. e. lossof a major 150 kV transmission line. Fastimplementation of the SVC was required toensure safe system operation within the shortesttime achievable. To achieve the tight schedule,a unique approach was chosen comprising aSVC design based on containerization to thegreatest extent possible to allow prefabrication,pre-installation and pre-commissioning of theSVC system at the manufacturer’s workshop.This reduced installation and commissioningtime on site and is a step forward fortransportable SVC’s that can be easily and


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economically relocated. The Jember SVC wasput into commercial operation 1995 in only 12months after contract signature.

USA: The Lugo SSR DamperThe SSR (Subsynchronous Resonances)damper scheme is a high voltage-thyristor circuitdesigned to solve a complex problem which in1970 and 1971 caused damage to the shafts ofa turbine-generator connected to the 500 kVtransmission network of the Southern CaliforniaEdison System. Analysis of the cause of thefailure identified the SSR phenomenon. SSRcan occur in electrical networks, which utilizehigh levels of conventional SCs to increasetransmission lines power carrying capability bycompensating the line series inductance. TheSSR problem occurs when the amount of SCcompensation results in an electrical circuitnatural frequency that coincides with, andthereby excites, one of the torsional naturalfrequencies of the turbine-generator shaft.

Dampening is achieved by using anti-parallelthyristor strings to discharge the SCs atcontrolled times. Network configurationsinvolving Southern California Edison’s Mohavegenerator were simulated and used to study theworst case SSR problem. In this case, with ahigh level of SC (70 percent), the effectivenessof the NGH scheme (comprising outdoor valvesat high-voltage potential platforms) wasevaluated. This device is in successfulcommercial operation since the 1980’s.

USA: The Kayenta TCSCIn the Western Area Power Administration(WAPA) system, USA, transmission of low-costand renewable hydroelectric energy was limitedby a major bottleneck in its high-voltagetransmission network. To overcome thislimitation, WAPA installed a TCSC device atKayenta Substation, Arizona – the first everthree-phase thyristor-controlled seriescompensator. The Kayenta installation, insuccessful commercial operation since 1992,provides for a power transfer increase of 33 %while maintaining reliable system operation. TheKayenta ASC has operated successfully underall system conditions, including severaltransmission line faults. This installationprovides the technology demonstrator for thistype of FACTS device, which, in addition tomaking better use of existing line capacity,

obviated the need for installing an extratransmission line by the local electrical utility.

Future Developments in FACTSFuture developments will include thecombination of existing devices, e.g. combininga STATCOM with a TSC (thyristor switchedcapacitor) to extend the operational range. Inaddition, more sophisticated control systems willimprove the operation of FACTS devices.Improvements in semiconductor technology (e.g.higher current carrying capability, higherblocking voltages) could reduce the costs ofFACTS devices and extend their operationranges. Finally, developments in superconductortechnology open the door to new devices likeSCCL (Super Conducting Current Limiter) andSMES (Super Conducting Magnetic EnergyStorage).

There is a vision for a high voltage transmissionsystem around the world – to generate electricalenergy economically and environmentallyfriendly and provide electrical energy where it’sneeded. FACTS are the key to make this visionlive.


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How the World Bank can facilitate increased usage of FACTS devices

Since FACTS devices facilitate economy and efficiency in power transmission systems in anenvironmentally optimal manner, they can make a very attractive addition to the World Bank’s portfolio ofpower projects. In spite of its attractive features, FACTS technology does not seem to be very well knownin the World Bank. The following is a proposed action plan for giving FACTS technology increasedexposure in the World Bank:(a) informing Bank staff and its stakeholders on FACTS technology, including case studies through

publishing relevant papers (such as this one) on its “Home Page” and as part of its EnergyIssues series;

(b) organizing presentations/workshops/training activities in connection with high profile events (suchas Energy Week) on FACTS technology as well as in the field to provide information toBorrowers. This has now occurred for the Greater Mekong Subregion (GMS) Workshop onEnergy Trade in Bangkok February 2000;

(c) conducting a review of its power sector portfolio over the last twenty years to quantify the level ofusage of FACTS devices in Bank projects and identifying lessons learned: and

(d) reviewing its lending pipeline to identify opportunities for increased usage of FACTS technology.

BoxDesign, Implementation, Operation and Training Needs of FACTS DevicesNetwork studies are very important for the implementation of a FACTS device to determine therequirements for the relevant installation. Experienced network planning engineers have to evaluate thesystem including future developments. Right device – right size – right place – right cost.

Reliable operation of FACTS devices require regular maintenance in addition to using equipment of thehighest quality standards. Maintenance requirements are minimal but important.

Optimal use of FACTS devices depend upon well-trained operators. Since most utility operators areunfamiliar with FACTS devices (compared with for example switched reactors or capacitors), training onthe operation of FACTS devices is therefore very important. What is important for the operators to know isare the appropriate settings of FACTS devices, especially the speed of response to changing phaseangle and voltage conditions as well as operating modes. This training would normally last one to twoweeks.

(1) Klaus Habur is Sr. Area Marketing Manager, Reactive Power Compensation, Power Transmission andDistribution Group (EV) of Siemens AG in Erlangen, Germany. Donal O’Leary, Sr. Power Engineer of the WorldBank is on assignment with the Siemens Power Generation Group (KWU) in Erlangen, Germany. This paper hasbeen reviewed by Messrs. Masaki Takahashi, Jean-Pierre Charpentier and Kurt Schenk of the World Bank.

anexo g - material de apoyo para estimado de costos opción ... · 1. se asume que el costo total...

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