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ANEXO G - Material de Apoyo para Estimado de Costos Opción Línea AC Pág. 128 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) MONTAJE 100,000.00 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 MONTAJE DE ESPACIADORES A. MONTAJE DE HERRAJES C.D.G. FUNDACIONES 18,000.00 500.00 33,333.33 TOTAL MONTAJE COSTO MONTAJE (US $ equiv./km) Factor Terreno Montañoso COSTO (MATERIAL + MONTAJE) 108,333.33 18% 245,833.33 Imprevistos (10%) 24,583.33 COSTO TOTAL UNITARIO Distancia (km) COSTO TOTAL 295,000.00 600 177,000,000.00 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 Venezuela Kenya Perú Uganda 225 250 260 295 375 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. ANEXO H - Material de Apoyo para Estimado de Costos Opción HVDC Pág. 129 Tabla H1 – Desglose de Costos para nueva Línea de Transmisión HVDC convencional @ ±250 kV ±250 kV DC Equipo Terminal HVDC Equipo Línea HVDC 120,000,000 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 Equipo Línea HVDC 120,000,000.00 - 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. 32 IEEE power & energy magazine 1540-7977/07/$25.00©2007 IEEE march/april 2007 H HIGH VOLTAGE DIRECT CURRENT (HVDC) TECHNOLOGY HAS characteristics that make it especially attractive for certain transmission applications. HVDC transmission is widely recognized as being advantageous for long-distance bulk-power delivery, asynchronous interconnections, and long submarine cable crossings. The number of HVDC projects committed or under consideration globally has increased in recent years reflecting a renewed interest in this mature technology. New converter designs have broadened the potential range of HVDC transmission to include applications for underground, offshore, economic replacement of reliability-must-run generation, and voltage stabilization. This broader range of applications has contributed to the recent growth of HVDC transmission. There are approximately ten new HVDC projects under construction or active consideration in North America along with many more projects underway globally. Figure 1 shows the Danish terminal for Skagerrak’s pole 3, which is rated 440 MW. Figure 2 shows the ±500-kV HVDC transmission line for the 2,000 MW Intermountain Power Project between Utah and California. This article discusses HVDC technologies, application areas where HVDC is favorable compared to ac transmission, system configuration, station design, and operating principles. Core HVDC Technologies Two basic converter technologies are used in modern HVDC transmission systems. These are conventional line-commutated current source converters (CSCs) and self-commutated voltage source converters (VSCs). Figure 3 shows a conventional HVDC converter station with CSCs while Figure 4 shows a HVDC converter station with VSCs. Line-Commutated Current Source Converter ©PHOTODISC march/april 2007 Conventional HVDC transmission employs line-commutated CSCs with thyristor valves. Such converters require a synchronous voltage source in order to operate. The basic building block used for HVDC conversion is the threephase, full-wave bridge referred to as a six-pulse or Graetz bridge. The term six-pulse is due to six commutations or switching operations per period resulting in a characteristic harmonic ripple of six times the fundamental frequency in the dc output voltage. Each six-pulse bridge is comprised of six controlled switching elements or thyristor valves. Each valve is comprised of a suitable number of series-connected thyristors to achieve the desired dc voltage rating. The dc terminals of two six-pulse bridges with ac voltage sources phase displaced by 30◦ can be connected in series to increase the dc voltage and eliminate some of the characteristic ac current and dc voltage harmonics. Operation in this manner is referred to as 12-pulse operation. In 12-pulse operation, the characteristic ac current and dc voltage harmonics have frequencies of 12n ± 1 and 12n, respectively. The 30◦ phase displacement is achieved by feeding one bridge through a transformer with a wye-connected secondary and the other bridge through a transformer with a delta-connected secondary. Most modern HVDC transmission schemes utilize 12-pulse converters to reduce the harmonic filtering requirements required for six-pulse operation; e.g., fifth and seventh on the ac side and sixth on the dc side. This is because, although these harmonic currents still flow through the valves and the transformer windings, they are IEEE power & energy magazine 33 180◦ out of phase and cancel out on the primary side of the converter transformer. Figure 5 shows the thyristor valve arrangement for a 12-pulse converter with three quadruple valves, one for each phase. Each thyristor valve is built up with series-connected thyristor modules. Line-commutated converters require a relatively strong synchronous voltage source in order to commutate. Commu- figure 1. HVDC converter station with ac filters in the foreground and valve hall in the background. figure 2. A ±500-kV HVDC transmission line. HVDC-CSC Converter Transformers ac tation is the transfer of current from one phase to another in a synchronized firing sequence of the thyristor valves. The three-phase symmetrical short circuit capacity available from the network at the converter connection point should be at least twice the converter rating for converter operation. Linecommutated CSCs can only operate with the ac current lagging the voltage, so the conversion process demands reactive power. Reactive power is supplied from the ac filters, which look capacitive at the fundamental frequency, shunt banks, or series capacitors that are an integral part of the converter station. Any surplus or deficit in reactive power from these local sources must be accommodated by the ac system. This difference in reactive power needs to be kept within a given band to keep the ac voltage within the desired tolerance. The weaker the ac system or the further the converter is away from generation, the tighter the reactive power exchange must be to stay within the desired voltage tolerance. Figure 6 illustrates the reactive power demand, reactive power compensation, and reactive power exchange with the ac network as a function of dc load current. Converters with series capacitors connected between the valves and the transformers were introduced in the late 1990s for weak-system, back-to-back applications. These converters are referred to as capacitor-commutated converters (CCCs). The series capacitor provides some of the converter reactive power compensation requirements automatically with load current and provides part of the commutation voltage, improving voltage stability. The overvoltage protection of the series capacitors is simple since the capacitor is not exposed to line faults, and the fault current for internal converter faults is limited by the impedance of the converter transformers. The CCC configuration allows higher power ratings in areas were the ac network is close to its voltage stability limit. The asynchronous Garabi interconnection between Brazil and Argentina consists of 4 × 550 MW parallel CCC links. The Rapid City Tie between the Eastern and Western interconnected systems consists of 2 × 100 MW parallel CCC links (Figure 7). Both installations use a modular design with converter valves located within prefabricated electrical enclosures rather than a conventional valve hall. d c Filters ac Filters dc Outdoor Indoor Thyristor Valves figure 3. Conventional HVDC with current source converters. 34 IEEE power & energy magazine Self-Commutated Voltage Source Converter HVDC transmission using VSCs with pulse-width modulation (PWM), commercially known as HVDC Light, was introduced in the late 1990s. Since then the progression to higher voltage and power ratings for these converters has roughly paralleled that for thyristor valve converters in the 1970s. These VSC-based systems are selfmarch/april 2007 commutated with insulated-gate bipolar transistor (IGBT) valves and solid-dielectric extruded HVDC cables. Figure 8 illustrates solid-state converter development for the two different types of converter technologies using thyristor valves and IGBT valves. HVDC transmission with VSCs can be beneficial to overall system performance. VSC technology can rapidly control both active and reactive power independently of one another. Reactive power can also be controlled at each terminal independent of the dc transmission voltage level. This control capability gives total flexibility to place converters anywhere in the ac network since there is no restriction on minimum network short-circuit capacity. Self-commutation with VSC even permits black start; i.e., the converter can be used to synthesize a balanced set of three phase voltages like a virtual synchronous generator. The dynamic support of the ac voltage at each converter terminal improves the voltage stability and can increase the transfer capability of the sending- and receiving-end ac systems, thereby leveraging the transfer HVDC-VSC capability of the dc link. Figure 9 shows the IGBT converter valve arrangement for a VSC station. Figure 10 shows the active and reactive power operating range for a converter station with a VSC. Unlike conventional ac HVDC transmission, the converters themselves have no reactive power demand and can actually control their reactive power to regulate ac system Outdoor voltage just like a generator. such as hydroelectric developments, mine-mouth power plants, or large-scale wind farms. Higher power transfers are possible over longer distances using fewer lines with HVDC transmission than with ac transmission. Typical HVDC lines utilize a bipolar configuration with two independent poles, one at a positive voltage and the other at a negative voltage with respect to ground. Bipolar HVDC lines are comparable to a double circuit ac line since they can operate at half power with one pole out of service but require only one-third the number of insulated sets of conductors as a double circuit ac line. Automatic restarts from temporary dc line fault clearing sequences are routine even for generator outlet transmission. No synchro-checking is required as for automatic reclosures following ac line faults since the dc restarts do not expose turbine generator units to high risk of transient torque amplification from closing into faults or across high phase angles. The controllability of HVDC links offer firm transmission capacity dc Indoor HVDC Applications HVDC transmission applications can be broken down into different basic categories. Although the rationale for selection of HVDC is often economic, there may be other reasons for its selection. HVDC may be the only feasible way to interconnect two asynchronous networks, reduce fault currents, utilize long underground cable circuits, bypass network congestion, share utility rightsof-way without degradation of reliability, and to mitigate environmental concerns. In all of these applications, HVDC nicely complements the ac transmission system. Long-Distance Bulk Power Transmission HVDC transmission systems often provide a more economical alternative to ac transmission for long-distance bulkpower delivery from remote resources march/april 2007 IGBT Valves figure 4. HVDC with voltage source converters. Thyristor Module Single Double Quadruple Valve Valve Thyristors figure 5. Thyristor valve arrangement for a 12-pulse converter with three quadruple valves, one for each phase. IEEE power & energy magazine 35 Furthermore, the long-distance ac lines usually require intermediate switching stations and reactive power compensation. 0,5 This can increase the substation costs for ac Converter transmission to the point where it is compaClassic Filter rable to that for HVDC transmission. Shunt Banks For example, the generator outlet trans0,13 mission alternative for the ±250-kV, 500Harmonic MW Square Butte Project was two 345-kV Filters ld 1.0 series-compensated ac transmission lines. Unbalance The 12,600-MW Itaipu project has half its figure 6. Reactive power compensation for conventional HVDC converter power delivered on three 800-kV seriesstation. compensated ac lines (three circuits) and the other half delivered on two ±600-kV bipolar without limitation due to network congestion or loop flow on HVDC lines (four circuits). Similarly, the ±500-kV, 1,600parallel paths. Controllability allows the HVDC to “leap-frog” MW Intermountain Power Project (IPP) ac alternative commultiple “choke-points” or bypass sequential path limits in the prised two 500-kV ac lines. The IPP takes advantage of the ac network. Therefore, the utilization of HVDC links is usual- double-circuit nature of the bipolar line and includes a 100% ly higher than that for extra high voltage ac transmission, low- short-term and 50% continuous monopolar overload. The first ering the transmission cost per MWh. This controllability can 6,000-MW stage of the transmission for the Three Gorges also be very beneficial for the parallel transmission since, by Project in China would have required 5 × 500-kV ac lines as eliminating loop flow, it frees up this transmission capacity for opposed to 2 × ±500-kV, 3,000-MW bipolar HVDC lines. its intended purpose of serving intermediate load and providTable 1 contains an economic comparison of capital costs ing an outlet for local generation. and losses for different ac and dc transmission alternatives for Whenever long-distance transmission is discussed, the a hypothetical 750-mile, 3,000-MW transmission system. The concept of “break-even distance” frequently arises. This is long transmission distance requires intermediate substations where the savings in line costs offset the higher converter sta- or switching stations and shunt reactors for the ac alternatives. tion costs. A bipolar HVDC line uses only two insulated sets The long distance and heavy power transfer, nearly twice the of conductors rather than three. This results in narrower surge-impedance loading on the 500-kV ac alternatives, rights-of-way, smaller transmission towers, and lower line require a high level of series compensation. These ac station losses than with ac lines of comparable capacity. A rough costs are included in the cost estimates for the ac alternatives. approximation of the savings in line construction is 30%. It is interesting to compare the economics for transmisAlthough break-even distance is influenced by the costs sion to that of transporting an equivalent amount of energy of right-of-way and line construction with a typical value of using other transport methods, in this case using rail trans500 km, the concept itself is misleading because in many portation of sub-bituminous western coal with a heat content cases more ac lines are needed to deliver the same power of 8,500 Btu/lb to support a 3,000-MW base load power over the same distance due to system stability limitations. plant with heat rate of 8,500 Btu/kWh operating at an 85% Q ld 1 Ua Ub Uc Valve Enclosures Commutation Capacitor Converter Transformer ++ Ula Uca l a + ++ Ulb Ucb l b + ++ Ulc + Ucc 3 5 lc 4 6 2 figure 7. Asynchronous back-to-back tie with capacitor-commutated converter near Rapid City, South Dakota. 36 IEEE power & energy magazine march/april 2007 load factor. The rail route is assumed to be longer than the more direct transmission route; i.e., 900 miles. Each unit train is comprised of 100 cars each carrying 100 tons of coal. The plant requires three unit trains per day. The annual coal transportation costs are about US$560 million per year at an assumed rate of US$50/ton. This works out to be US$186 kW/year and US$25 per MWh. The annual diesel fuel consumed in the process is in excess of 20 million gallons at 500 net ton-miles per gallon. The rail transportation costs are subject to escalation and congestion whereas the transmission costs are fixed. Furthermore, transmission is the only way to deliver remote renewable resources. 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 70 19 73 19 76 19 Thyristor MW 79 19 82 19 85 19 90 19 93 19 Thyristor KV 96 999 002 005 008 1 2 2 19 2 IGBT MW 11 20 IGBT kV figure 8. Solid-state converter development. Underground and Submarine Cable Transmission Unlike the case for ac cables, there is no physical Submodule restriction limiting the distance or power level for HVDC underground or submarine cables. UnderChip StakPak ground cables can be used on shared rights-ofway with other utilities without impacting reliability concerns over use of common corridors. IGBT Valve For underground or submarine cable systems there is considerable savings in installed cable costs and cost of losses when using HVDC transmission. Depending on the power level to be Cable transmitted, these savings can offset the higher converter station costs at distances of 40 km or more. Furthermore, there is a drop-off in cable figure 9. HVDC IGBT valve converter arrangement. capacity with ac transmission over distance due to its reactive component of charging current since cables have higher capacitances and lower inductances than ac (MINDs) used for conventional HVDC transmission, thus overhead lines. Although this can be compensated by interme- making them more conducive for land cable applications diate shunt compensation for underground cables at increased where transport limitations and extra splicing costs can drive expense, it is not practical to do so for submarine cables. up installation costs. The lower-cost cable installations made For a given cable conductor area, the line losses with possible by the extruded HVDC cables and prefabricated HVDC cables can be about half those of ac cables. This is joints makes long-distance underground transmission ecodue to ac cables requiring more conductors (three phases), nomically feasible for use in areas with rights-of-way concarrying the reactive component of current, skin-effect, and straints or subject to permitting difficulties or delays with induced currents in the cable sheath and armor. overhead lines. With a cable system, the need to balance unequal loadings or the risk of postcontingency overloads often necessitates Asynchronous Ties use of a series-connected reactors or phase shifting trans- With HVDC transmission systems, interconnections can be formers. These potential problems do not exist with a con- made between asynchronous networks for more economic or reliable system operation. The asynchronous interconnection trolled HVDC cable system. Extruded HVDC cables with prefabricated joints used allows interconnections of mutual benefit while providing a with VSC-based transmission are lighter, more flexible, and buffer between the two systems. Often these interconnections easier to splice than the mass-impregnated oil-paper cables use back-to-back converters with no transmission line. march/april 2007 IEEE power & energy magazine 37 Asynchronous HVDC links act as an effective “firewall” against propagation of cascading outages in one network from passing to another network. Many asynchronous interconnections exist in North America between the Eastern and Western interconnected systems, between the Electric Reliability Council of Texas (ERCOT) and its neighbors, [e.g., Mexico and the Southwest Power Pool (SPP)], and between Quebec and its neighbors (e.g., New England and the Maritimes). The August 2003 Active Power (p.u.) Northeast blackout provides an example of the “firewall” against cascading outages provided by asynchronous interconnections. As the outage expanded and propagated around the lower Great Lakes and through Ontario and New York, it stopped at the asynchronous interface with Quebec. Quebec was unaffected; the weak ac interconnections between New York and New England tripped, but the HVDC links from Quebec continued to deliver power to New England. Regulators try to eliminate “seams” in electrical networks because of their potential restriction on power markets. Electrical “seams,” P-Q Diagram however, serve as natural points of separa1.25 1.25 tion by acting as “shear-pins,” thereby reducing the impact of large-scale system 1 disturbances. Asynchronous ties can eliminate market “seams” while retaining natu0.75 ral points of separation. Interconnections between asynchronous Operating Area 0.5 networks are often at the periphery of the respective systems where the networks tend 0.25 to be weak relative to the desired power transfer. Higher power transfers can be achieved with improved voltage stability in −1.25 −1 −0.75 −0.5 −0.25 0 0.25 0.5 0.75 1 1.25 weak system applications using CCCs. The −0.25 dynamic voltage support and improved voltage stability offered by VSC-based convert−0.5 ers permits even higher power transfers without as much need for ac system rein−0.75 forcement. VSCs do not suffer commutation failures, allowing fast recoveries from near−1 by ac faults. Economic power schedules that reverse power direction can be made 1.25 −1.25 without any restrictions since there is no Reactive Power (p.u.) minimum power or current restrictions. HVDC VSC Operating Range figure 10. Operating range for voltage source converter HVDC transmission. 2 x 40 MW VSC HVDC figure 11. VSC power supply to Troll A production platform. 38 IEEE power & energy magazine Offshore Transmission Self-commutation, dynamic voltage control, and black-start capability allow compact VSC HVDC transmission to serve isolated loads on islands or offshore production platforms over long-distance submarine cables. This capability can eliminate the need for running expensive local generation or provide an outlet for offshore generation such as that from wind. The VSCs can operate at variable frequency to more efficiently drive large compressor or pumping loads using high-voltage motors. Figure 11 shows the Troll A production platform in the North Sea where power to drive compressors is delivered from shore to reduce the higher carbon emissions and higher O&M costs associated with less efficient platform-based generation. Large remote wind generation arrays require a collector system, reactive power march/april 2007 march/april 2007 154 5.12% $196 48 4.79% $61 106 5.29% $135 139 4.62% $177 208 6.93% $265 208 6.93% $265 10% $1,500 Parameters: Interest rate % Capitalized cost of losses $/kW Note: AC current assumes 94% pf Full load converter station losses = 9.75% per station Total substation losses (transformers, reactors) assumed = 0.5% of rated power 103 3.43% $131 134 3.35% $171 193 6.44% $246 Losses @ full load Losses at full load in % Capitalized cost of losses @ $1500 kW (M$) 148 4.93% $188 $363 $80.66 $10.83 $191 $127.40 $17.11 $172 $57.28 $7.69 $512 $170.77 $22.93 $312 $104.03 $13.97 $376 $125.24 $16.82 $209 $69.75 $9.37 $327 $81.68 $10.97 $172 $57.28 $7.69 Annual Payment, 30 years @ 10% Cost per kW-Yr Cost per MWh @ 85% Utilization Factor $193 $64.18 $8.62 1,500 $2,700 $3,422 $722 $302 $2.00 750 $1,500 $1,802 $420 $1.60 750 $1,200 $1,620 $630 $2.80 1,500 $4,200 $4,830 $542 $3.20 750 $2,400 $2,942 $542 $2.00 1,500 $3,000 $3,542 $510 $1.95 750 $1,463 $1,973 $680 $1.60 1,500 $2,400 $3,080 $420 $1.60 750 $1,200 $1,620 $465 $1.80 750 $1,350 $1,815 4500 1500 3000 3000 3000 3000 3000 3000 4000 Hybrid AC/DC Alternative + 500 kV 500 kV Total Bipole Single Ckt AC + DC AC Alternatives 500 kV 765 kV Double Ckt 2 Singl Ckt 500 kV 2 Single Ckt +800 kV Bipole DC Alternatives 2 x + 500 kV + 600 kV 2 bipoles Bipole 3000 Power supply for large cities depends on local generation and power import capability. Local Capital Cost Rated Power (MW) Station costs including reactive compenstation (M$) Transmission line cost (M$/mile) Distance in miles Transmission Line Cost (M$) Total Cost (M$) Power Delivery to Large Urban Areas + 500 Kv Bipole Most HVDC systems are for point-to-point transmission with a converter station at each end. The use of intermediate taps is rare. Conventional HVDC transmission uses voltage polarity reversal to reverse the power direction. Polarity reversal requires no special switching arrangement for a twoterminal system where both terminals reverse polarity by control action with no switching to reverse power direction. Special dc-side switching arrangements are needed for polarity reversal in a multiterminal system, however, where it may be desired to reverse the power direction at a tap while maintaining the same power direction on the remaining terminals. For a bipolar system this can be done by connecting the converter to the opposite pole. VSC HVDC transmission, however, reverses power through reversal of the current direction rather than voltage polarity. Thus, power can be reversed at an intermediate tap independently of the main power flow direction without switching to reverse voltage polarity. Alternative Multiterminal Systems table 1. Comparative costs of HVDC and EHV AC transmission alternatives. support, and outlet transmission. Transmission for wind generation must often traverse scenic or environmentally sensitive areas or bodies of water. Many of the better wind sites with higher capacity factors are located offshore. VSC-based HVDC transmission allows efficient use of long-distance land or submarine cables and provides reactive support to the wind generation complex. Figure 12 shows a design for an offshore converter station designed to transmit power from offshore wind generation. IEEE power & energy magazine 39 generation is often older and less efficient than newer units located remotely. Often, however, the older, less-efficient units located near the city center must be dispatched out-ofmerit because they must be run for voltage support or reliability due to inadequate transmission. Air quality regulations may limit the availability of these units. New transmission into large cities is difficult to site due to right-of-way limitations and land-use constraints. Compact VSC-based underground transmission circuits can be placed on existing dual-use rights-of-way to bring in power as well as to provide voltage support, allowing a more economical power supply without compromising reliability. The receiving terminal acts like a virtual generator delivering power and supplying voltage regulation and dynamic reactive power reserve. Stations are compact and housed mainly indoors, making siting in urban areas somewhat easier. Furthermore, the dynamic voltage support offered by the VSC can often increase the capability of the adjacent ac transmission. System Configurations and Operating Modes figure 12. VSC converter for offshore wind generation. Monopole, Ground Return Figure 13 shows the different common system configurations and operating modes used for HVDC transmission. Monopolar systems are the simplest and least expensive systems for moderate power transfers since only two converters and one high-voltage insulated cable or line conductor are required. Such systems have been used with low-voltage electrode lines and sea electrodes to carry the return current in submarine cable crossings. In some areas conditions are not conducive to monopolar earth or sea return. This could be the case in heavily congested Bipole Bipole, Series-Connected Converters Monopole, Metallic Return Bipole, Metallic Return Monopole, Midpoint Grounded Back-to-Back Multiterminal figure 13. HVDC configurations and operating modes. 40 IEEE power & energy magazine march/april 2007 ac Switchyard Converter Transformers ac Line Valve Hall Shunt Capacitors dc Line Harmonic Filters dc Switchyard figure 14. Monopolar HVDC converter station. areas, fresh water cable crossings, or areas with high earth converter for each pole at each terminal. This gives two inderesistivity. In such cases a metallic neutral- or low-voltage pendent dc circuits each capable of half capacity. For normal cable is used for the return path and the dc circuit uses a simple balanced operation there is no earth current. Monopolar earth local ground connection for potential reference only. Back-to- return operation, often with overload capacity, can be used back stations are used for interconnection of asynchronous net- during outages of the opposite pole. works and use ac lines to connect on either side. In such Earth return operation can be minimized during monopolar systems power transfer is limited by the relative capacities of outages by using the opposite pole line for metallic return via the adjacent ac systems at the point of connection. pole/converter bypass switches at each end. This requires a As an economic alternative to a monopolar system with metallic-return transfer breaker in the ground electrode line at metallic return, the midpoint of a 12-pulse converter can be connected to earth directly or through an impedance and two Coolers half-voltage cables or line conductors can be used. The converter is only operated in 12-pulse mode so there is never any stray earth current. VSC-based HVDC transmission is usually arranged with a single converter connected pole-to-pole rather than poleto-ground. The center point of the converter is connected to ground through a IGBT Valve high impedance to provide a reference Enclosures for the dc voltage. Thus, half the convertPhase er dc voltage appears across the insulaReactors tion on each of the two dc cables, one positive the other negative. ac Filters The most common configuration for modern overhead HVDC transmission lines is bipolar with a single 12-pulse figure 15. VSC HVDC converter station. march/april 2007 IEEE power & energy magazine 41 one of the dc terminals to commutate the current from the relatively low resistance of the earth into that of the dc line conductor. Metallic return operation capability is provided for most dc transmission systems. This not only is effective during converter outages but also during line insulation failures where the remaining insulation strength is adequate to withstand the low resistive voltage drop in the metallic return path. For very-high-power HVDC transmission, especially at dc voltages above ±500 kV (i.e., ±600 kV or ±800 kV), seriesconnected converters can be used to reduce the energy unavailability for individual converter outages or partial line insulation failure. By using two series-connected converters per pole in a bipolar system, only one quarter of the transmission capacity is lost for a converter outage or if the line insulation for the affected pole is degraded to where it can only support half the rated dc line voltage. Operating in this mode also avoids the need to transfer to monopolar metallic return to limit the duration of emergency earth return. walls for connection to the valves. Double or quadruple valve structures housing valve modules are used within the valve hall. Valve arresters are located immediately adjacent to the valves. Indoor motor-operated grounding switches are used for personnel safety during maintenance. Closed-loop valve cooling systems are used to circulate the cooling medium, deionized water or water-glycol mix, through the indoor thyristor valves with heat transfer to dry coolers located outdoors. Area requirements for conventional HVDC converter stations are influenced by the ac system voltage and reactive power compensation requirements where each individual bank rating may be limited by such system requirements as reactive power exchange and maximum voltage step on bank switching. The ac yard with filters and shunt compensation can take up as much as three quarters of the total area requirements of the converter station. Figure 14 shows a typical arrangement for an HVDC converter station. VSC-Based HVDC Station Design and Layout Conventional HVDC The converter station layout depends on a number of factors such as the dc system configuration (i.e., monopolar, bipolar, or back-to-back), ac filtering, and reactive power compensation requirements. The thyristor valves are air-insulated, water-cooled, and enclosed in a converter building often referred to as a valve hall. For back-to-back ties with their characteristically low dc voltage, thyristor valves can be housed in prefabricated electrical enclosures, in which case a valve hall is not required. To obtain a more compact station design and reduce the number of insulated high-voltage wall bushings, converter transformers are often placed adjacent to the valve hall with valve winding bushings protruding through the building ac Bus Control ID The transmission circuit consists of a bipolar two-wire HVDC system with converters connected pole-to-pole. DC capacitors are used to provide a stiff dc voltage source. The dc capacitors are grounded at their electrical center point to establish the earth reference potential for the transmission system. There is no earth return operation. The converters are coupled to the ac system through ac phase reactors and power transformers. Unlike most conventional HVDC systems, harmonic filters are located between the phase reactors and power transformers. Therefore, the transformers are exposed to no dc voltage stresses or harmonic loading, allowing use of ordinary power transformers. 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 of series-connected IGBT positions. The IGBT is a hybrid device exhibiting the low forward drop of a bipolar transistor as a dc Line R Control TCP TCP Udl UdR Id IR α IS IT ac Bus u α IR uR ∼ I uS S ∼ uT IT ∼ 1 3 5 u uT Ud uR 4 6 2 uS figure 16. Conventional HVDC control. 42 IEEE power & energy magazine march/april 2007 conducting device. Instead of the regular current-controlled base, the IGBT has a voltage-controlled capacitive gate, as in the MOSFET device. A complete IGBT position consists of an IGBT, an antiparallel diode, a gate unit, a voltage divider, and a watercooled heat sink. Each gate unit includes gate-driving circuits, surveillance circuits, and optical interface. The gatedriving electronics control the gate voltage and current at turn-on and turn-off to achieve optimal turn-on and turn-off processes of the IGBTs. To be able to switch voltages higher than the rated voltage of one IGBT, many positions are connected in series in each valve similar to thyristors in conventional HVDC valves. All IGBTs must turn on and off at the same moment to achieve an evenly distributed voltage across the valve. Higher currents are handled by paralleling IGBT components or press packs. The primary objective of the valve dc-side capacitor is to provide a stiff voltage source and a low-inductance path for the turn-off switching currents and to provide energy storage. The capacitor also reduces the harmonic ripple on the dc voltage. Disturbances in the system (e.g., ac faults) will cause dc voltage variations. The ability to limit these voltage variations depends on the size of the dc-side capacitor. Since the dc capacitors are used indoors, dry capacitors are used. AC filters for VSC HVDC converters have smaller ratings than those for conventional converters and are not required for reactive power compensation. Therefore, these filters are always connected to the converter bus and not switched with transmission loading. All equipment for VSC-based HVDC converter 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 are as follows: 1) to control basic system quantities such as dc line current, dc voltage, and transmitted power accurately and with sufficient speed of response 2) to maintain adequate commutation margin in inverter operation so that the valves can recover their forward blocking capability after conduction before their voltage polarity reverses 3) to control higher-level quantities such as frequency in isolated mode or provide power oscillation damping to help stabilize the ac network 4) to compensate for loss of a pole, a generator, or an ac transmission circuit by rapid readjustment of power 5) to ensure stable operation with reliable commutation in the presence of system disturbances 6) to minimize system losses and converter reactive power consumption 7) to ensure proper operation with fast and stable recoveries during ac system faults and disturbances. ac Line Voltages OPWM uDC2 uDC1 uAC-ref1 − uAC1 i i − uDC-ref2− uDC-ref1 + + ac Voltage Control qref1 dc Voltage Control PWM Internal Current Control pref1 pref2 uAC-ref2 ac Voltage Control + dc Voltage Control uAC2 PWM Internal Current Control qref2 Principle Control of HVDC-Light figure 17. Control of VSC HVDC transmission. march/april 2007 IEEE power & energy magazine 43 For conventional HVDC transmission, one terminal sets the dc voltage level while the other terminal(s) regulates the (its) dc current by controlling its output voltage relative to that maintained by the voltage-setting terminal. Since the dc line resistance is low, large changes in current and hence power can be made with relatively small changes in firing angle (alpha). Two independent methods exist for controlling the converter dc output voltage. These are 1) by changing the ratio between the direct voltage and the ac voltage by varying the delay angle or 2) by changing the converter ac voltage via load tap changers (LTCs) on the converter transformer. Whereas the former method is rapid the latter method is slow due to the limited speed of response of the LTC. Use of high delay angles to achieve a larger dynamic range, however, increases the converter reactive power consumption. To minimize the reactive power demand while still providing adequate dynamic control range and commutation margin, the LTC is used at the rectifier terminal to keep the delay angle within its desired steady-state range (e.g., 13–18◦ ) and at the inverter to keep the extinction angle within its desired range (e.g., 17–20◦ ), if the angle is used for dc voltage control or to maintain rated dc voltage if operating in minimum commutation margin control mode. Figure 16 shows the characteristic transformer current and dc bridge voltage waveforms along with the controlled items Ud, Id, and tap changer position (TCP). VSC-Based HVDC Power can be controlled by changing the phase angle of the converter ac voltage with respect to the filter bus voltage, whereas the reactive power can be controlled by changing the magnitude of the fundamental component of the converter ac voltage with respect to the filter bus voltage. By controlling these two aspects of the converter voltage, operation in all four quadrants is possible. This means that the converter can be operated in the middle of its reactive power range near unity power factor to maintain dynamic reactive power reserve for contingency voltage support similar to a static var compensator. It also means that the real power transfer can be changed rapidly without altering the reactive power exchange with the ac network or waiting for switching of shunt compensation. Being able to independently control ac voltage magnitude and phase relative to the system voltage allows use of separate active and reactive power control loops for HVDC system regulation. The active power control loop can be set to control either the active power or the dc-side voltage. In a dc link, one station will then be selected to control the active power while the other must be set to control the dc-side voltage. The reactive power control loop can be set to control either the reactive power or the ac-side voltage. Either of these two modes can be selected independently at either end of the dc link. Figure 17 shows the characteristic ac voltage waveforms before and after the ac filters along with the controlled items Ud, Id, Q, and Uac. 44 IEEE power & energy magazine Conclusions The favorable economics of long-distance bulk-power transmission with HVDC together with its controllability make it an interesting alternative or complement to ac transmission. The higher voltage levels, mature technology, and new converter designs have significantly increased the interest in HVDC transmission and expanded the range of applications. For Further Reading B. Jacobson, Y. Jiang-Hafner, P. Rey, and G. Asplund, “HVDC with voltage source converters and extruded cables for 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 project second 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-West interconnection,” 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 the Nicolet Converter Station into the Quebec-New England Phase II transmission system,” in Proc. CIGRÉ 1994, Paris, France. A. Ekstrom and G. Liss, “A refined HVDC control system,” IEEE Trans. Power Systems, vol. PAS-89, pp. 723–732, May-June 1970. Biographies Michael P. Bahrman received a B.S.E.E. from Michigan Technological University. He is currently the U.S. HVDC marketing and sales manger for ABB Inc. He has 24 years of experience with ABB Power Systems including system analysis, system design, multiterminal HVDC control development, and project management for various HVDC and FACTS projects in North America. Prior to joining ABB, he was with Minnesota Power for 10 years where he held positions as transmission planning engineer, HVDC control engineer, and manager of system operations. He has been an active member of IEEE, serving on a number of subcommittees and working groups in the area of HVDC and FACTS. Brian K. Johnson received the Ph.D. in electrical engineering from the University of Wisconsin-Madison. He is currently a professor in the Department of Electrical and Computer Engineering at the University of Idaho. His interests include power system protection and the application of power electronics to utility systems, security and survivability of ITS systems and power systems, distributed sensor and control networks, and real-time simulation of traffic systems. He is a member of the Board of Governors of the IEEE Intelligent Transportation Systems Society and the Administrative Committee of the IEEE p&e Council on Superconductivity. march/april 2007 ANEXO I - Material de Apoyo para Estimado de Costos Opciones E, F y G Pág. 130 Tabla I1 – Desglose de Costos para nuevo equipo TCSC en la S/E Cotaruse TCSC US$/kVAr Costo de Equipamiento Obras de Montaje 150 MVAr 70 10,500,000 850,000 Obras Civiles 1,250,000 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 US$/kVAr Costo de Equipamiento 150 MVAr 30 4,500,000 Obras de Montaje 350,000 Obras Civiles 550,000 Otros 450,000 TOTAL 5,850,000 El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 6 (o Exhibit 5) muestra rangos de costos unitarios en US$/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$/kVAr 65.00 Costo de Equipamiento 9,750,000 Obras de Montaje Obras Civiles Otros TOTAL 775,000 1,175,000 975,000 12,675,000 El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 5 (o Exhibit 5) muestra rangos de costos unitarios en US$/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 MATERIALES CONDUCTOR 500 kV SIMPLE TERNA US $/km 23,000.00 Base de Datos Propia MATERIALES 500 kV SIMPLE TERNA US $/km 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) MONTAJE DEFORESTACION 130,500.00 US $/km 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 MONTAJE DE ESPACIADORES A. MONTAJE DE HERRAJES C.D.G. FUNDACIONES 17,000.00 3,000.00 500.00 35,000.00 TOTAL MONTAJE COSTO MONTAJE (US $ equiv./km) Factor Terreno Montañoso COSTO (MATERIAL + MONTAJE) 123,000.00 18% 299,130.00 Base de Datos Propia MATERIALES Imprevistos (20%) COSTO TOTAL UNITARIO Distancia (km) COSTO TOTAL 500 kV SIMPLE TERNA US $/km 59,826.00 358,956.00 815 292,549,140.00 Solo Línea AC Costo de Equipamiento 125,501,850.00 Obras de Montaje 84,629,600.00 Obras Civiles 33,659,500.00 Otros 48,758,190.00 TOTAL 292,549,140.00 Extensión S/E Celdas 8,000,000.00 TOTAL Costo de Equipamiento 133,501,850.00 Obras de Montaje 84,629,600.00 Obras Civiles 33,659,500.00 Otros 48,758,190.00 TOTAL 300,549,140.00 Se asumieron costos asociados a terreno montañoso (caso de la costa), lo que se muestra como factor terreno montañoso. Así mismo, se asumió una extensión en las subestaciones asociadas con la línea en 500 kV. El costo unitario equivalente es de casi kUS$ 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$/kVAr 15.00 Costo de Equipamiento 9,000,000 Obras de Montaje Obras Civiles Otros TOTAL 700,000 1,100,000 900,000 11,700,000 El artículo incluido al final de este anexo muestra información de costos reciente publicada en un esfuerzo conjunto del Banco Mundial y Siemens AG. En dicho artículo se encuentra información de utilidad para este estimado. Por ejemplo, la Figura 6 (o Exhibit 6) muestra rangos de costos unitarios en US$/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%. 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 transmission systems (FACTS) devices are used for the dynamic control of voltage, impedance and phase angle of high voltage AC lines. FACTS devices provide strategic benefits for improved transmission system management through: better utilization of existing transmission assets; increased transmission system reliability and availability; increased dynamic and transient grid stability; increased quality of supply for sensitive industries (e.g. computer chip manufacture); and enabling environmental benefits. Typically the construction period for a facts device is 12 to 18 months from contract signing through commissioning. This paper starts by providing definitions of the most common application of FACTS devices as well as enumerates their benefits (focussing on steady state and dynamic applications). Generic information on the costs and benefits of FACTS devices is then provided as well as the steps for identification of FACTS projects. The paper then discusses seven applications of FACTS devices in Australia, Brazil, Indonesia, South Africa and the USA. The paper concludes with some recommendations on how the World Bank could facilitate the increased usage of FACTS. Introduction The need for more efficient electricity systems management has given rise to innovative technologies in power generation and transmission. The combined cycle power station is a good example of a new development in power generation and flexible AC transmission systems, FACTS as they are generally known, are new devices that improve transmission systems. Worldwide transmission systems are undergoing continuous changes and restructuring. They are becoming more heavily loaded and are being operated in ways not originally envisioned. Transmission systems must be flexible to react to more diverse generation and load patterns. In addition, the economical utilization of transmission system assets is of vital importance to enable utilities in industrialized countries to remain competitive and to survive. In developing countries, the optimized use of transmission systems investments is also important to support industry, create employment and utilize efficiently scarce economic resources. Flexible AC Transmission Systems (FACTS) is a technology that responds to these needs. It significantly alters the way transmission systems are developed and controlled together with improvements in asset utilization, system flexibility and system performance. What are FACTS devices? FACTS devices are used for the dynamic control of voltage, impedance and phase angle of high voltage AC transmission lines. Below the different main types of FACTS devices are described: Static Var Compensators (SVC’s), the most important FACTS devices, have been used for a number of years to improve transmission line economics by resolving dynamic voltage problems. The accuracy, availability and fast response enable SVC’s to provide high performance steady state and transient voltage control compared with classical shunt compensation. SVC’s are also used to dampen power swings, improve transient stability, and reduce system losses by optimized reactive power control. Thyristor controlled series compensators (TCSCs) are an extension of conventional series capacitors through adding a thyristor-controlled reactor. Placing a controlled reactor in parallel Page 1 of 11 FACTS – For cost effective and reliable transmission of electrical energy with a series capacitor enables a continuous and rapidly variable series compensation system. The main benefits of TCSCs are increased energy transfer, dampening of power oscillations, dampening of subsynchronous resonances, and control of line power flow. STATCOMs are GTO (gate turn-off type thyristor) based SVC’s. Compared with conventional SVC’s (see above) they don’t require large inductive and capacitive components to provide inductive or capacitive reactive power to high voltage transmission systems. This results in smaller land requirements. An additional advantage is the higher reactive output at low system voltages where a STATCOM can be considered as a current source independent from the system voltage. STATCOMs have been in operation for approximately 5 years. Unified Power Flow Controller (UPFC). Connecting a STATCOM, which is a shunt connected device, with a series branch in the transmission line via its DC circuit results in a UPFC. This device is comparable to a phase shifting transformer but can apply a series voltage of the required phase angle instead of a voltage with a fixed phase angle. The UPFC combines the benefits of a STATCOM and a TCSC. Exhibit 1: UPFC circuit diagram The section on Worldwide Applications contains descriptions of typical applications for FACTS devices. Benefits of utilizing FACTS devices The benefits of utilizing FACTS devices in electrical transmission systems can be summarized as follows: • Better utilization of existing transmission system assets • Increased transmission system reliability and availability • Increased dynamic and transient grid stability and reduction of loop flows • Increased quality of supply for sensitive industries • Environmental benefits Better utilization of existing transmission system assets In many countries, increasing the energy transfer capacity and controlling the load flow of transmission lines are of vital importance, especially in de-regulated markets, where the locations of generation and the bulk load centers can change rapidly. Frequently, adding new transmission lines to meet increasing electricity demand is limited by economical and environmental constraints. FACTS devices help to meet these requirements with the existing transmission systems. Increased transmission system reliability and availability Transmission system reliability and availability is affected by many different factors. Although FACTS devices cannot prevent faults, they can mitigate the effects of faults and make electricity supply more secure by reducing the number of line trips. For example, a major load rejection results in an over voltage of the line which can lead to a line trip. SVC’s or STATCOMs counteract the over voltage and avoid line tripping. Increased dynamic and transient grid stability Long transmission lines, interconnected grids, impacts of changing loads and line faults can create instabilities in transmission systems. These can lead to reduced line power flow, loop flows or even to line trips. FACTS devices stabilize transmission systems with resulting Page 2 of 11 FACTS – For cost effective and reliable transmission of electrical energy higher energy transfer capability and reduced risk of line trips. Increased quality of supply for sensitive industries Modern industries depend upon high quality electricity supply including constant voltage, and frequency and no supply interruptions. Voltage dips, frequency variations or the loss of supply can lead to interruptions in manufacturing processes with high resulting economic losses. FACTS devices can help provide the required quality of supply. Environmental benefits FACTS devices are environmentally friendly. They contain no hazardous materials and produce no waste or pollutanse. FACTS help distribute the electrical energy more economically through better utilization of existing installations thereby reducing the need for additional transmission lines. Applications and technical benefits of FACTS devices Exhibits 2 to 4 below describe the technical benefits of the principal FACTS devices including steady state applications in addressing problems of voltage limits, thermal limits, loop flows, short circuit levels and subsynchronous resonance. For each problem the conventional solution (e.g. shunt reactor or shunt capacitor) is also provided (as well as for dynamic applications – see below), as well as dynamic applications of FACTS in addressing problems in transient stability, dampening, post contingency voltage control and voltage stability. FACTS devices are required when there is a need to respond to dynamic (fast-changing) network conditions. The conventional solutions are normally less expensive than FACTS devices – but limited in their dynamic behavior. It is the task of the planners to identify the most economic solution. In Exhibits 3 and 4 information is provided on FACTS devices with extensive operational experience and widespread use such as SVC, STATCOM, TCSC and UPFC. In addition, information is provided on FACTS devices that are either under discussion, development or as prototype in operation such as the thyristor controlled phase-angle regulator (TCPAR); the thyristor controlled voltage limiter (TCVL); and the thyristor switched series capacitor (TCSC). Technical benefits of the main FACTS devices Better Exhibit 2: Benefits of FACTS devices for different applications Page 3 of 11 FACTS – For cost effective and reliable transmission of electrical energy Steady state applications of FACTS Issue Voltage limits Problem Corrective Action Low voltage at heavy Supply reactive power load High voltage at light load Remove reactive power supply Absorb reactive power High voltage following outage Low voltage following outage Thermal limits Loop flows Low voltage and overload Line or transformer overload Tripping of parallel circuit (line) Parallel line load sharing Post-fault sharing Short circuit levels Subsynchronous resonance Flow direction reversal Excessive breaker fault current Potential turbine /generator shaft damage Legend for Exhibit 3 NGH = Hingorani Damper PAR = Phase-Angle-Regulator SCCL = Super-Conducting Current Limiter SVC = Static Var Compensator STATCOM = Static Compensator TCPAR = Thyristor Controlled Phase-Angle Regulator Absorb reactive power Protect equipment Supply reactive power Prevent overload Supply reactive power and limit overload Reduce overload Limit circuit (line) loading Adjust series reactance Adjust phase angle Rearrange network or use “Thermal limit” actions Adjust phase angle Limit short circuit current Change circuit breaker Rearrange network Mitigate oscillations TCSC TCVL TSBR TSSC UPFC Conventional solution Shunt capacitor, Series capacitor Switch EHV line and/or shunt capacitor Switch shunt capacitor, shunt reactor Add shunt reactor Add arrestor Switch shunt capacitor, reactor, series capacitor Series reactor, PAR Combination of two or more devices Add line or transformer Add series reactor Add series reactor, capacitor Add series capacitor/reactor Add PAR PAR, Series Capacitor/Reactor FACTS device SVC, TCSC, STATCOM PAR Add series reactor, new circuit breaker Add new circuit breaker Split bus series compensation TCPAR, UPFC SCCL, UPFC, TCSC SVC, TCSC, STATCOM SVC, STATCOM SVC, STATCOM SVC SVC, STATCOM TCPAR, TCSC TCSC, UPFC, STATCOM, SVC TCSC, UPFC, TCPAR SVC, TCSC UPFC, TCSC UPFC, TCSC TCPAR, UPFC TCSC, UPFC, SVC, TCPAR NGH, TCSC = Thyristor Controlled Series Capacitor = Thyristor Controlled Voltage Limiter = Thyristor Switched Braking Resistor = Thyristor Switched Series Capacitor = Unified Power Flow Controller Exhibit 3: Steady state applications of FACTS FACTS are a well-proven technology. The first installations were put into service over 20 years ago. As of January 2000, the total worldwide installed capacity of FACTS devices is more than 40,000 MVAr in several hundred installations. While FACTS devices are used primarily in the electricity supply industry, they are also used in computer hardware and steel manufacturing (SVC’s for flicker compensation), as well as for voltage control in transmission systems for railways and in research centers (e.g. CERN in Geneva). Page 4 of 11 FACTS – For cost effective and reliable transmission of electrical energy Dynamic applications of FACTS Issue Transient Stability Type of System A, B, D A, D B, C, D Dampening A B, D Post Contingency Voltage Control A, B, D A, B, C, D Voltage Stability B, C, D Corrective Action Increase synchronizing torque Absorb kinetic energy Dynamic load flow control Dampen 1 Hz oscillations Dampen low frequency oscillations Dynamic voltage support Dynamic flow control Dynamic voltage support and flow control Reduce impact of contingency Reactive Support Network control actions Generation control Load control Legend for Exhibit 4: A. Remote Generation – Radial Lines (e.g. Namibia) C. Tightly meshed network (e.g. Western Europe) BESS HVDC LTC NGH PAR SCCL SMES = Battery Energy Storage System = High Voltage Direct Current = Transformer-Load Tap Changer = Hingorani Damper = Phase-Angle Regulator = Super-Conducting Current Limiter = Super-Conducting Magnetic Energy Storage B. D. Conventional Solution High-response exciter, series capacitor Braking resistor, fast valving (turbine) HVDC FACTS device TCSC, TSSC, UPFC Exciter, Power system stabilizer (PSS), - Power system stabilizer (PSS) - SVC, TCSC, STATCOM parallel lines shunt capacitor, shunt reactor LTC, reclosing, HVDC controls High-response exciter Under-voltage load shedding Demand-Side Management Programs TCBR, SMES, BESS TCPAR, UPFC, TCSC SVC, TCPAR, UPFC, NGH, TCSC, STATCOM SVC, STATCOM, UPFC, SVC, UPFC, TCPAR SVC, UPFC, TCSC SVC, TCSC, STATCOM, , UPFC SVC, STATCOM, UPFC UPFC, TCSC, STATCOM - Interconnected Areas (e.g. Brazil) Loosely meshed network (e.g. Queensland, Austr.) STATCOM = Static Synchronous Compensator SVC TCPAR TCSC TCVL TSBR TSSC UPFC = Static Var Compensator = Thyristor Controlled Phase-Angle Regulator = Thyristor Controlled Series Capacitor = Thyristor Controlled Voltage Limiter = Thyristor Switched Braking Resistor = Thyristor Switched Series Capacitor = Unified Power Flow Controller Exhibit 4: Dynamic applications of FACTS Investment costs of FACTS devices. The investment costs of FACTS devices can be broken down into two categories: (a) the devices’ equipment costs, and (b) the necessary infrastructure costs. Equipment costs Equipment costs depend not only upon the installation rating but also upon special requirements such as: • redundancy of the control and protection system or even main components such as reactors, capacitors or transformers, • seismic conditions, • ambient conditions (e.g. temperature, pollution level): and • communication with the Substation Control System or the Regional or National Control Center. Page 5 of 11 FACTS – For cost effective and reliable transmission of electrical energy Infrastructure Costs Infrastructure costs depend on the substation location, where the FACTS device should be installed. 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, thyristor valves, auxiliaries etc.), • yard civil works (grading, drainage, foundations etc.), and • connection of the existing communication US$/kVAr For typical devices’ratings, the lower limit of the cost areas shown in Exhibits 5 and 6 indicates the equipment costs, and the upper limit indicates the total investment costs including the infrastructure costs. For very low ratings, costs can be higher and for very high power ratings costs can be lower than indicated. The total investment costs shown, which are exclusive of taxes and duties, may vary due to the described factors by –10% to +30%. Including taxes and duties, which differ significantly between different countries, the total investment costs for FACTS devices may vary even more. US$/kVAr 160 160 140 140 120 120 100 STATCOM 100 TCSC 80 80 60 UPFC SVC 60 40 40 20 20 100 200 FSC 400 500 300 Operating Range in MVAr 100 Source: Siemens AG Database Source: Siemens AG Database system with the new installation. Exhibit 5: Typical investment costs for SVC / Statcom 400 500 200 300 O p e r a t in g R a n g e in M V A r Exhibit 6: Typical investment cost for SC, TCSC and UPFC M ill. US$ What are the financial benefits of FACTS devices? There are three areas were the financial benefits could 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 even new power generation. 160 140 500 kV 120 100 80 345 kV 60 220 kV 40 132 kV 20 100 Exhibit 7 gives indicates the possible additional sales in US$ per year based on different energy 200 300 Source: Siemens AG Database 400 500 Length of Line in km Exhibit 7: Overview yearly sales Page 6 of 11 FACTS – For cost effective and reliable transmission of electrical energy costs / prices when a transmission line capacity can be increased. Exhibit 8 below gives some indication of typical investment costs for new high voltage AC transmission lines. 0,06 140 120 0,04 100 80 60 0,02 US$ per kWh Additional sales in Mill. US$ 160 40 0,01 20 50 100 150 200 250 MW Additional transmission capacity of a line Source: Siemens AG Database Exhibit 8: Typical costs of new AC transmission lines Example 1: If through using a FACTS device, a fully loaded transmission line’s capability could be increased by 50 MW (e.g. for transmission lines of 132 kV or higher), this could generate additional sales of 50 MW equivalent. Assuming a 100% load factor and a sales price of 0.02 US$ per kWh, this would result in additional annual electricity sales of up to US$ 8.8 million. Example 2: Assume that the investment costs of a 300 km long 400 kV line are approx. US$. 45 million. At an interest rate of 10%, this results in annual interest costs of US$ 4,5 million. Installation of a FACTS device for e.g. US$ 20 million could be economically justified, if such an investment can be avoided or delayed by at least 5 years (5 times 4,5 = 22.5). The above examples are only rough calculations to indicate the possible direct economical benefits of FACTS devices. There are also indirect benefits of utilizing FACTS devices, which are more difficult to calculate. These include avoidance of industries’ outage costs due to interruption of production processes (e.g. paper industry, textile industry, production of semi-conductors / computer chips) or load shedding during peak load times. Maintenance of FACTS devices Maintenance of FACTS devices is minimal and similar to that required for shunt capacitors, reactors and transformers. It can be performed by normal substation personnel with no special procedures. The amount of maintenance ranges from 150 to 250 man-hours per year and depends upon the size of the installation and the local ambient (pollution) conditions. Operation of FACTS devices FACTS devices are normally operated automatically. They can be located in unmanned substations. Changing of set-points or operation modes can be done locally and remotely (e.g. from a substation control room, a regional control centre, or a national control centre). Steps for the Identification of FACTS Projects 1. The first step should always be to conduct a detailed network study to investigate the critical conditions of a grid or grids’connections . These conditions could include: risks of voltage problems or even voltage collapse, undesired power flows, as well as the potential for power swings or subsynchronous resonances. 2. For a stable grid, the optimized utilization of the transmission lines – e.g. increasing the energy transfer capability – could be investigated. 3. If there is a potential for improving the transmission system, either through enhanced stability or energy transfer capability, the appropriate FACTS device and its required rating can be determined. 4. Based on this technical information, an economical study can be performed to compare costs of FACTS devices or conventional solutions with the achievable benefits. Performance Verification The design of all FACTS devices should be tested in a transient network analyzer (TNA) under all possible operational conditions and fault scenarios. The results of the TNA tests should be consistent with the results of the network study, which was performed at the start of the project. The results of the TNA study also Page 7 of 11 FACTS – For cost effective and reliable transmission of electrical energy provide the criteria for the evaluation of the site commissioning 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 going to site and • of the commissioning tests on site ensures the required functionality of the FACTS devices. Worldwide Applications Seven projects are described below, where FACTS devices have proven their benefits over several years. These descriptions also indicate how the FACTS devices were designed to meet the different requirements of the seven transmission systems. The investment costs for these devices are consistent with the information presented in Exhibits 4 and 5 above. The construction period for a FACTS device is typically 12 to 18 months from contract signing through commissioning. Installations with a high degree of complexity,, comprehensive approval procedures, and time-consuming equipment tests may have longer construction periods. The Australian Interconnector The interconnection of the South Australian, Victoria and New South Wales Systems involved transmission at voltages up to 500 kV over distances exceeding 2200 km. The interconnection is for interchange of 500 MW. Two identical – 100 MVAr (inductive) /+ 150 MVAr (capacitive) SVC’s at Kemps Creek improve transient stability. Here each SVC consists of two thyristor-switched capacitors and a thyristor-switched reactor that can be switched in combination to provide uniform steps across the full control range. To ensure reliable operation under all power system conditions, the implementation of the SVC design had to be carefully evaluated prior to installation. The behavior of the SVC was examined at a transient network analyzer under a wide range of system conditions. The three-state interconnected system and the two SVC’s were successfully put into commercial operation in spring 1990. The two SVC’s are equipped only with thyristor-switched reactors and capacitors with the advantage that no harmonics are generated and therefor no filters are necessary. The system operates as expected and proved the original concepts. As part of the interconnected system, the compensators at Kemps Creek have been called upon on several occasions to support the system and have done so in an exemplary manner. SOUTH AFRICA: Increase in Line Capacity with SVC The Kwazulu-Natal system of the Eskom Grid, South Africa, serves two major load centers (Durban and Richards Bay) at the extremities of the system. In 1993, the system was loaded close to its voltage stability limit, a situation aggravated by the lack of base load generation capacity in the area. The 1000 MW Drakensberg pumped storage scheme, by the nature of its duty cycle and location remote from the main load centers, does not provide adequate capacity. Exhibit 9: SOUTH AFRICA: SVC, Illovo. The installation of three SVCs in the major load centers provides superior voltage control performance compared to an additional new line subject to load switching. A further motivation for choosing SVCs in this case are their lower capital cost, reduced environmental impact, and the minimization of fault-induced voltage reductions compared to building additional transmission lines. Faultinduced voltage reductions cause major disruption of industrial processes, and mainly result from transmission line faults. The frequency of such reductions is proportional to the total line length exposed to the failure mechanisms (viz. sugar cane fires), resulting in Page 8 of 11 FACTS – For cost effective and reliable transmission of electrical energy a desire to minimize the total length of transmission lines. These SVCs went into commercial operation in 1995. BRAZIL: North – South Interconnection In Brazil there are two independent transmission grids, the North grid and the South grid. These two grids cover more than 95% of the electric power transmission in the country. Detailed studies demonstrated the economic attractiveness of connecting the two grids. Inter alia they compared the attractiveness of building an AC or a HVDC (High Voltage Direct Current) connection of more than 1.000 km long passing through an area with a fast growing economy and also with a high hydropower potential. As it is technically much easier and more economical to build new connections to an AC line than to an HVDC line it was decided to build a new AC line. shafts in thermal power stations. Under certain conditions SSRs can damage the shaft of the turbine – generator unit, which results in high repair costs and lost generation during the unit repair time. USA: More Effective Long-Distance HVDCSystem A major addition to the 500 kV transmission system between Arizona and California, USA, was installed to increase power transfer. This addition includes two new series - compensated 500 kV lines and two large SVC’s. These SVC’s are needed to provide system security, safe and secure power transmission, and support the nearby HVDC station of the Los Angeles Department of Water and Power (LADWP). By installing the SVCs, the LADWP ensured its capability to supply high quality electric power to ist major customers and to minimize the risk of supply interruptions. The control design for these SVC’s, based on detailed analysis, is driven by the unique system requirement of dampening the complex oscillation modes between Arizona and California. Extensive testing on a real-time simulator was done, including the HVDC system originally delivered by another manufacturer before the controls were delivered on site. Field tests during and after commissioning verified these results. These SVC’s, ones of the largest installations ever delivered, went into commercial operation early 1996. Exhibit 10: BRAZIL: TCSC, Serra de Mesa The line, which is now in operation since beginning of 1999, is equipped with SC’s (Series Capacitors) and TCSC’s (Controlled Series Capacitors) to reduce the transmission losses and to stabilize the line. Initial studies indicated the potential for low frequency power oscillations between the two grids which TCSC’s can dampen and thereby mitigate the risk of line instability. In addition, the application of TCSCs can effectively reduce the risk of subsynchronous resonances (SSRs) caused by the application of SC’s in a line. SSRs in a transmission system are resonance phenomena between the electrical system and the mechanical system of turbine – generator INDONESIA: Containerized Design Load flow and stability studies of the Indonesian power system identified the need for a SVC with a control range of – 25 MVAr to + 50 MVAr at Jember Substation(Bali). The SVC provides fast voltage control to allow enhanced power transfer under extreme system contingencies, i. e. loss of a major 150 kV transmission line. Fast implementation of the SVC was required to ensure safe system operation within the shortest time achievable. To achieve the tight schedule, a unique approach was chosen comprising a SVC design based on containerization to the greatest extent possible to allow prefabrication, pre-installation and pre-commissioning of the SVC system at the manufacturer’s workshop. This reduced installation and commissioning time on site and is a step forward for transportable SVC’s that can be easily and Page 9 of 11 FACTS – For cost effective and reliable transmission of electrical energy economically relocated. The Jember SVC was put into commercial operation 1995 in only 12 months after contract signature. obviated the need for installing an extra transmission line by the local electrical utility. Future Developments in FACTS USA: The Lugo SSR Damper The SSR (Subsynchronous Resonances) damper scheme is a high voltage-thyristor circuit designed to solve a complex problem which in 1970 and 1971 caused damage to the shafts of a turbine-generator connected to the 500 kV transmission network of the Southern California Edison System. Analysis of the cause of the failure identified the SSR phenomenon. SSR can occur in electrical networks, which utilize high levels of conventional SCs to increase transmission lines power carrying capability by compensating the line series inductance. The SSR problem occurs when the amount of SC compensation results in an electrical circuit natural frequency that coincides with, and thereby excites, one of the torsional natural frequencies of the turbine-generator shaft. Dampening is achieved by using anti-parallel thyristor strings to discharge the SCs at controlled times. Network configurations involving Southern California Edison’s Mohave generator were simulated and used to study the worst case SSR problem. In this case, with a high level of SC (70 percent), the effectiveness of the NGH scheme (comprising outdoor valves at high-voltage potential platforms) was evaluated. This device is in successful commercial operation since the 1980’s. Future developments will include the combination of existing devices, e.g. combining a STATCOM with a TSC (thyristor switched capacitor) to extend the operational range. In addition, more sophisticated control systems will improve the operation of FACTS devices. Improvements in semiconductor technology (e.g. higher current carrying capability, higher blocking voltages) could reduce the costs of FACTS devices and extend their operation ranges. Finally, developments in superconductor technology open the door to new devices like SCCL (Super Conducting Current Limiter) and SMES (Super Conducting Magnetic Energy Storage). There is a vision for a high voltage transmission system around the world – to generate electrical energy economically and environmentally friendly and provide electrical energy where it’s needed. FACTS are the key to make this vision live. USA: The Kayenta TCSC In the Western Area Power Administration (WAPA) system, USA, transmission of low-cost and renewable hydroelectric energy was limited by a major bottleneck in its high-voltage transmission network. To overcome this limitation, WAPA installed a TCSC device at Kayenta Substation, Arizona – the first ever three-phase thyristor-controlled series compensator. The Kayenta installation, in successful commercial operation since 1992, provides for a power transfer increase of 33 % while maintaining reliable system operation. The Kayenta ASC has operated successfully under all system conditions, including several transmission line faults. This installation provides the technology demonstrator for this type of FACTS device, which, in addition to making better use of existing line capacity, Page 10 of 11 FACTS – For cost effective and reliable transmission of electrical energy How the World Bank can facilitate increased usage of FACTS devices Since FACTS devices facilitate economy and efficiency in power transmission systems in an environmentally optimal manner, they can make a very attractive addition to the World Bank’s portfolio of power projects. In spite of its attractive features, FACTS technology does not seem to be very well known in the World Bank. The following is a proposed action plan for giving FACTS technology increased exposure 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 Energy Issues series; (b) organizing presentations/workshops/training activities in connection with high profile events (such as Energy Week) on FACTS technology as well as in the field to provide information to Borrowers. This has now occurred for the Greater Mekong Subregion (GMS) Workshop on Energy Trade in Bangkok February 2000; (c) conducting a review of its power sector portfolio over the last twenty years to quantify the level of usage 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. Box Design, Implementation, Operation and Training Needs of FACTS Devices Network studies are very important for the implementation of a FACTS device to determine the requirements for the relevant installation. Experienced network planning engineers have to evaluate the system 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 the highest quality standards. Maintenance requirements are minimal but important. Optimal use of FACTS devices depend upon well-trained operators. Since most utility operators are unfamiliar with FACTS devices (compared with for example switched reactors or capacitors), training on the operation of FACTS devices is therefore very important. What is important for the operators to know is are the appropriate settings of FACTS devices, especially the speed of response to changing phase angle and voltage conditions as well as operating modes. This training would normally last one to two weeks. (1) Klaus Habur is Sr. Area Marketing Manager, Reactive Power Compensation, Power Transmission and Distribution Group (EV) of Siemens AG in Erlangen, Germany. Donal O’Leary, Sr. Power Engineer of the World Bank is on assignment with the Siemens Power Generation Group (KWU) in Erlangen, Germany. This paper has been reviewed by Messrs. Masaki Takahashi, Jean-Pierre Charpentier and Kurt Schenk of the World Bank. Page 11 of 11