Download ANEXO G - Material de Apoyo para Estimado de Costos Opción

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