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HVDC Systems in Smart Grids

Mike Barnes, Senior Member, IEEE, Dirk van Hertem, Simon P. Teeuwsen, and Magnus Callavik

switch off at zero, or nearly zero, current making them

Abstract— The use of DC power networks, either at high cheaper and more compact.
voltage or at medium voltage, is being increasingly seen in  DC machines require brushes, induction machines do not
modern smart grids. This is due to the flexible control possible – an advantage in terms of robustness. Induction
with DC and its ability to transmit and distribute power under
circumstance where AC networks are either unable to, or less
machines have gone on to become a, if not the, dominant
economic. This paper provides an overview of the evolution of electrical load.
High Voltage DC transmission from early Thury systems, to
A. First Applications
modern ultra-high voltage DC and multi-terminal voltage-source
converter systems. The operation of both current-source and Despite the initial advantages of AC, DC was still used in a
voltage source systems is discussed, along with modelling number of installations in the subsequent decades, particularly
requirements. The paper provides a snapshot of the state-of-the- when two different unsychronised, or different frequency, AC
art of HVDC with copious references to enable in-depth reading. systems needed to be connected. In this case the AC:DC:AC
Key developments over the last twenty years are highlighted.
HVDC link acted as a buffer to connect the two. Between the
Issues surrounding multi-terminal operation and DC protection
are explained as are drivers in economics and policy. 1880’s and 1930’s a number of HVDC installations were
employed. These used the Thury system, where voltage
Index Terms—Power conversion, power system control, power conversion was accomplished by back-to-back motor-
grids, power transmission, smart grids, HVDC transmission. generator sets [3]. The Moutiers-Lyons line was the most
powerful such system: running from 1906 to 1936 in France,
I. INTRODUCTION AND HISTORY over at distance of 200km at +/-75kV with a current of 150A

W HETHER AC or DC is a better solution for electrical

transmission was debated since the first days of
electrical power. The famous ‘war of currents’ in the 1880’s
(or about 22MW).
B. Line Commutated HVDC History
and 1890’s between Edison, proposing DC, and By the 1930’s, the concept of rectification with a mercury
Westinghouse, championing AC, was a prime example. arc, demonstrated in 1902 by Peter Hewitt [5], had reached a
Despite lurid initial claims about the dangers of AC, publicity level of development that allowed mercury arc rectifiers to be
stunts, and even the electrocution of the circus elephant Topsy used with moderate power AC-DC-AC conversion systems.
[2], AC initially ‘won’ the contest [1]. Tesla’s invention of the Examples included: 110kV 2-phase AC-AC converters
induction machine and advances in transformers, meant that coupling the 50 Hz network to a 16 2/3 Hz electric railway
network in 1932 (Siemens); BBC, a precursor company to
AC at the time had too many advantages, namely:
ABB, connecting a 3MW supply to the 110kV German
 In the 19th century, only transformers allowed efficient
network at Pforzheim the same year [6]. Experience with the
conversion between voltages. This permitted generation
technology developed, until between 1942 and 1944, Siemens
and end use at low voltage, but transformation to high
(with AEG) built a 60MW, 115km +/-200kV transmission
voltage for efficient long-distance transmission. This
line. At the end of World War Two, this was transferred to the
situation remained largely unchanged until mercury arc
Soviet Union, serving as the Moscow-Kashira 30MW, 112km
rectifiers became sufficiently advanced in the 1950’s.
HVDC system [6].
 AC currents are easier to interrupt, since they fall to zero
The development of the mercury arc rectifier’s capability by
twice per electrical cycle. A circuit breaker can therefore
Uno Lamm and his team at ASEA (now part of ABB) in the
1930’s and 1940’s led to the first ‘modern’ commercial
This work is support by the IEEE Working Groups 15.05.18 “Studies for HVDC system the 20MW, 98km, 100kV system linking the
Planning of HVDC” and 15.05.19 “Practical Technologies for VSC HVDC
Systems”
island of Gotland and the Swedish mainland [7]. This led to
M Barnes, is with the School of Electrical and Electronic Engineering, the rapid development of the technology reaching +/-250kV
University of Manchester, Manchester, M13 9PL, UK (email: and 600MW in 1965 with the first New Zealand Inter-Island
mike.barnes@manchester.ac.uk)
D Van Hertem is with KU Leuven, Department of Electrical Engineering
link and +/-400kV 1440MW in the USA Pacific Intertie in
(ESAT) in Leuven, Belgium and with EnergyVille, Electrical systems, Genk, 1970 [8].
Belgium (email: dirk.vanhertem@ieee.org) From the early 1970’s onwards mercury arc rectifiers
S Teeuwsen is with Siemens AG, Large Transmission Solutions, HVDC & started to be replaced with thyristor valves, which had matured
FACTS, Erlangen, Germany (email: simonp.teeuwsen@siemens.com)
M Callavik is with ABB Power Grids, Grid System, Master Ahls gata 8, as a technology from their introduction in the 1950’s. As solid
721 78 Västerås, Sweden, magnus.callavik@se.abb.com. state devices they did not suffer the material deposition
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problems that mercury arc devices did, which limited mercury block AC power flow quickly (in AC timescales) means that
arc device voltage, and required considerable maintenance [9]. power can be fed through the HVDC link into a system, but
Thyristors unlike mecury arc rectifiers also do not suffer from minimal extra fault current is added to the AC network.
operational problems like arc-backs [31]. Thyristor projects Consequently AC switchgear need not be upgraded. Often this
have now reached 8000MW +/-800kV over a 2210km HVDC connection is through back-to-back AC:DC:AC
distance (the Hami-Zhengzhou project commissioned in 2014 stations on one site. This was one of the advantages of VSC
[31]) with constructions of the Changji-Guquan 1100kV link HVDC for ABB’s Mackinac converter project in Michigan
to push powers to 13GW per line. [29].
Both mercury arc rectifiers and thyristors can delay turn-on Fourth, HVDC can transmit more power for a given
of their valves but in effect require the assistance of the AC transmission corridor size than AC. Where space is
grid to commutate (switch) from one valve to another. As Line constrained this may mean in future HV AC lines may be
Commutated Converters (LCC) this places minimum strength replaced by HVDC. This has been the case in Germany for the
requirements on the AC grid to which they are connected. Ultranet project [27]. Other examples for this type of HVDC
Their operation can be considered to be a DC current source, connection are DC links directly into the downtown area of
switched between AC phases by the combined action of the large cities like New York (Hudson Project) and San
AC grid and thyristor control, hence also the name Current Francisco (Transbay Cable).
Source Converters (CSC). Lastly VSC HVDC can provide a variety of power quality
support functions. Thus reactive power support, AC voltage
C. Voltage Source HVDC History
control and black-start functionality can be provided, again a
The recent development of Insulated Gate Bipolar key factor in ABB’s Mackinac project in Michigan [29].
Transistors (IGBTs), and other self-commutating high-voltage However since the total current capability of the VSC
high-current semiconductor switches, has led to the rise of converter is current and voltage limited, such additional
Voltage Source Converter (VSC) HVDC. These devices can functionality requires careful coordination with the converter’s
control both switch turn-on and turn-off allowing a DC real power import and export capability. Other functions
voltage source (hence the name VSC) to be switched between include: firewalling one AC system so that disturbances do not
phases. Since the first such installation in Hällsjon, Sweden in spread to an adjacent system; providing frequency stabilizing
1997, a 3MW, +/-10kV system, power has risen to 2000MW functions, provide artificial fast frequency response (also
(INELFE) [10] and a voltage of 500kV (Skagerrak 4) [11]. called artificial inertia, as implemented in the Caprivi Link
project); providing power oscillation damping (such as
II. KEY DRIVERS FOR HVDC IN SMARTGRIDS implemented in the Pacific DC Intertie, INELFE, BritNed,
At the time of writing HVDC has become widely used for ATCO, WATL) [33]; stabilizing the AC system (in New
transmission systems. These are multiple instances where Zealand: Fault Recovery Modulation, Frequency Keeping
HVDC provides greater flexibility or functionality, can Control, Frequency Stabilization Control, Spinning Reserve
connect systems that AC cannot, or can transmit more power Sharing, Constant Frequency Control, Wellington Over-
in a given space than AC can. HVDC is preferred over AC in Frequency Brake, Automatic Governor Control) [61,62]
several cases.
First if two unsynchronized AC networks, or AC networks
of differing frequency, need to be connected, HVDC can act
as a frequency and phase conversion stage. Examples of this
are the HVDC connections between the UK and Europe,
where two systems operate at 50Hz nominal frequency but are
not synchronized.
Second, for very long distances HVDC may be more
economical. This is because HVDC lines are cheaper per km
than AC, and unlike AC, HVDC lines do not consume reactive
power, and therefore are not limited by length or the
requirement for periodic reactive power compensation.
Moreover, the losses of a DC line are smaller than the losses
of an AC line due to high voltages and thus lower currents.
HVDC stations are more expensive than AC stations, so the
breakeven point is typically 600-800km for overhead lines or Fig. 1. German PlannedNorth-South Corridors Connections [27]
50-100km for cables (which have higher reactive power
exchange per km), depending on location, project power and According to a recent industry report the market is split
voltage [31]. Examples of such HVDC connections are many roughly equally between CSC and VSC technologies [26].
long distance lines in China, Brazil, Canada, and USA. CSC HVDC is presently preferred for very large bulk power
Third, two AC systems may need to be connected without transfer. The more compact VSC is used when space is at a
increasing AC fault level. The ability of the HVDC system to premium or additional services are required at the grid
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connection point. the first decade of the 21st century). In 2010 Siemens and ABB
Renewables will form an increasing fraction of generation, set a new upper voltage target of +/-800kV in the form of the
and transmitting such power to the point of use will be a major Siemens Yunnan-Guangdong 1418km, 5000MW project and
driver for long transmission corridors. This can be seen in the the ABB Xianjiaba-Shanghai SGCC Project, China 1980km,
VSC HVDC networks linking offshore windfarms to shore in 6400MW project, Fig. 3, [8]. The inauguration of the Hami-
Northern Germany (see also section III.E). HVDC connections Zhengzhou HVDC line raised this to 8000MW at +/-800kV
in Germany are the first step, Fig. 1, to transmit this offshore over 2210km [31]. This step in voltage was economical for the
wind from Northern Germany to industrial centers in Southern increased power requirement (5000MW or more) and distance
Germany. Similarly LCC HVDC connections like the Three covered (more than 1000 to 2500km) [12]. A substantial
Gorges Project in China transmit hydropower to the country’s amount of research was required both to reassess the internal
growing mega-cities [30]. and external electrical field design of the system, as well as to
The increase in demand in urban and industrial centers, both provide type testing at this new voltage, which required the
as a result of demographic, lifestyle and industrial changes, extensive use of demonstrators [12].
will require extra power. Since urban space is often
constrained and expensive, and utilities do not wish to uprate
other utility infrastructure, VSC-HVDC, and its medium
voltage variant, MVDC, may become a replacement solution
for AC to increase supplied power. They may also be used to
connect AC bulk-supply points, reinforcing the network,
without increasing fault level.
‘Supergrids’ – large meshed HVDC networks - have been
proposed [27] and radial networks are starting to be
constructed, see section III.F. These would potentially allow
transcontinental (or even intercontinental) sharing of
resources. For example in Europe offshore wind power from
the UK could be shared with Norwegian hydropower and
storage, Icelandic thermal energy generation and solar power Fig. 3. Xianjiaba-Shangahi SGCC Project, China, UHVDC Valve Hall
from Spain (as well as from other countries and conventional
generation). The different demand profiles in the continent’s
B. Pioneering VSC-HVDC Stations
countries could be smoothed out over time and energy traded
optimizing generation investment and utilization. A number of Following a technological review of the HVDC sector in
technical problems remain before this vision can be realized the 1990’s by ABB [13], it was found that scope existed for a
though. complementary VSC product to established CSC technologies.
An initial proof-of-concept installation at Hällsjőn in 1997
(3MW, +/10kV DC, 10km) [14] was followed the first
III. HVDC DEVELOPMENT OVER THE LAST 20 YEARS
commercial installation at Gotland in 1999 (50MW, +/-80kV,
A. Ultra-High Voltage DC Transmission 70km) [15], Fig. 4.
The principle development of LCC over the last two
decades has been in the increase of operational voltage, Fig. 2.

Fig. 4. Gotland HVDC Light Link converter station

Fig. 2. Progression of Voltage and Power Ratings for LCC and VSC HVDC
(Data from [9] and company websites) ABB rapidly developed the technology and three years later
in 2002 installations that used +/-150kV were available,
Although previous projects have used +/-600kV (Itaipu1 namely Cross Sound (330MW, 40km) [16] in the USA and
and 2, each 3150MW), most projects in previous decades had Murraylink (220MW, 180km) in Australia [17], Fig. 5. Many
limited themselves to +/-500kV (e.g. Three-Gorges and Gui- of these early installations were influenced by the desire to
Guang in China or the East-South Interconnector in India in minimize the environmental impact and the need to manage
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and minimize potential power quality issues on the AC side. formed by switching multiple modules to form a staircase
Low profile stations, fed by cables, with self-commutating output (see section V.A). All manufacturers have since moved
VSC, producing low amounts of low frequency harmonics to some form of a modular converter.
were a clear advantage.

Fig. 7. Transbay Cable HVDC Station (Copyright Hawkeye, "Courtesy of

Siemens", [63])

Fig. 5. Cable Laying for Murraylink E. German Offshore Windfarms

Following on from the success of the Troll offshore
C. Troll – First Offshore VSC HVDC platform, the utility TenneT and the German government have
pioneered the development offshore connection of windfarms
VSC HVDC has a significantly smaller footprint than LCC,
through VSC HVDC [28], Fig. 8. At the time of writing, over
and so is ideally suited for use offshore. The controllability of 4GW of VSC-HVDC transmission is available to allow
the converter also makes it highly suited to weaker grids. This offshore renewable energy to be fed to the mainland. Initial
was utilized in the first offshore station in 2005, where a 70km projects experienced some delay to the complex offshore
+/-60kV DC cable fed two 44MW gas compressor drives on environment. Type testing and prototyping on demonstrators
the offshore Troll gas mining platform, Fig. 4 [18]. is possible with onshore installations – this is not practical for
The success of this first Troll system was underlined by a large offshore installations connected to distributed energy
second system powering the Valhall platform in 2011 and sources like offshore wind - some initial learning in such large
another set of drives on the Troll field being powered by a industrial projects is not uncommon. The delivery of five
further VSC HVDC project in 2015 [18]. offshore HVDC connections in 2015 though has shown that
this is now a well-understood solution.

Fig. 6. Troll A HVDC Platform Fig. 8. German HVDC Connected Offshore Windfarm Locations [63]
D. Transbay Cable – First MMC Systems F. Multi-terminal VSC HVDC
In 2010 Siemens installed its first VSC HVDC system in HVDC with LCC has largely been a point-to-point solution.
San-Francisco, USA. VSC HVDC has previously used two- Historically multi-terminal installations have been few and far
and three-level converter designs. The Trans-bay Cable between though more recently they have attracted
project (400MW, +/-200kV and 85km long) [19], Fig. 7, was considerable attention as VSC HVDC has developed.
the first to use a Modular Multi-level Converter of the type The Hydro-Quebec System designed in the 1980’s is often
proposed by Marquardt [20]. In this, instead of an AC cited as the original HVDC multi-terminal system, based on
waveform being synthesized by pulse width modulation, it is initial studies for a five-terminal system [21]. The initial point-
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to-point system was meant to be expanded to this in two stages fundamental at the output of the converter, Fig. 10. This
– in practice a separate three-terminal link was constructed for phase-shift is the ‘turn on delay angle’, . Commutation
phase two [22], in part due to the consideration that a different between phases causes an additional voltage drop which is
vendor might be used. In practice this three-terminal link has proportional to the DC current. The constant of proportionality
predominantly spent its time operating as a unidirectional is modelled as a commutation resistance (RC).
system, either transferring hydropower from Radisson to
Sandy Pond or Radisson to Nicolet stations.
In 1967 a 200MW, monopolar LCC 200kV DC link
between Italy and Sardinia was established. In 1986-7 a
50MW tap was added [21]. This is known as the SACOI
(Sardinia-Corsica-Italy) link. However fast-reversing switches
were required to allow rectifier/inverter operation of the
Corsican station.
The 2016 North-East Agra LCC HVDC Link is a +/-800kV
6000MW, four terminal, three converter station [32]. This is
designed to supply hydropower from the North-East India.
A collaborative, government sponsored project to build a
back-to-back multi-terminal VSC-HVDC station at the Shin-
Shinano substation in Tokyo was undertaken by Toshiba,
Fig. 10. Simplified single-line diagram of 3-phase LCC HVDC 12-pulse
Hitachi and Mitsubishi Electric in the 1990s. The 300MW bridge (fundamental voltage and unfolded DC component of current shown at
back-to-back station used GTOs [23]. thyristor converter terminals)
The first VSC HVDC multi-terminal network systems are
the Chinese Nan’ao Island (2013) and Zhoushan (2014) VSC- The DC output voltage of one 6-pulse bridge is given by:
3 2E (1)
HVDC systems, Fig. 9 [25]. Nan’ao Island is a +/-160kV three VDC cos R I
terminal (200MW, 150MW, 50MW) collaboration between  C d

Rongxin Power Electronic, NR-Electric and XiDian [24]. where E is the line-to-line RMS AC voltage at the converter
Zhoushan is a five-terminal (400MW, 300MW and three times terminals [34]. The square wave pattern of the output current
100MW) +/-200kV system built by C-EPRI and NR Electric is rich in low order harmonics, hence a 12-pulse configuration
[25]. Both systems are radial networks - as yet no meshed of two bridges (and sometimes a higher number) is used, with
one connection transformer connected star:star and one
HVDC grids have been constructed.
star:delta, Fig. 10, to cancel 5th and 7th harmonics in steady
state. Further harmonic filters are required. Since phase shift
between AC voltage and current controls power flow, this
results in reactive power consumption. Local reactive power
compensation is thus typically required. Tap changing
transformers are typically used with a slow outer control loop,
to keep the turn-on advance angle within a tolerance band that
does not exceed limits which would either consume too much
reactive power or cause problems with converter control.

Fig. 9. Zhoushan Five Terminal VSC HVDC Network [25]

IV. MODERN LINE-COMMUTATED CONVERTER HVDC

Line Commutated Converter HVDC, by virtue of its
longevity, is well covered in a number of textbooks for
example [34-36]. This section provides a brief introduction.
A. Hardware and Control
The fundamental building block of a line-commutated
converter is the 12-pulse thyristor bridge, Fig. 10, made up of
two 6-pulse bridges. A large inductor on the DC side ensures
that the DC side appears as a source of nearly DC current.
Mercury arc valves, or now stacks of series connected
thyristors, switch this DC current between phases ‘unfolding
Fig. 11. Skaggerak HVDC system – lower half LCC Bipole, Upper half
it’ in to an AC waveform. This consists of an AC fundamental Hybrid LCC and VSC HVDC system
current phase-shifted with respect to the AC voltage
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From (1) it is evident that the converter is operating as a variables (i.e. telecommunication between stations is used to
rectifier with <90: positive DC voltage and current results enhance operation, but is not critical for normal stable
in power flow from the AC to the DC side. A turn on delay operation). The schemes use (1) in a variety of forms, a
angle above 90will cause the DC output voltage to go theoretical example of which is shown in, Fig. 12. Each line
negative and the converter becomes an inverter: power flows segment utilizes a different control to manipulate equation (1)
from DC to AC. The terminals of the converter can be or (its equivalent for the inverter). In segment AB the DC
mechanically reconnected in the reverse direction to voltage is limited, in BC is held constant and hence
accommodate this, Fig. 11. changing DC current causes DC voltage to change, and in CD’
The arrangement in Fig. 10 is known as a monopolar the current is held constant. D’F represents a Voltage
arrangement and requires and earth return, typically via a Dependent Current Limit (VDCL) to manage behavior at low
cable or line. More usually a second 12-pulse bridge of the voltages (of the bang-bang type).
opposite polarity is used in a so-called bipole, Fig. 11. Both The inverter characteristics CZ, again represents an inverter
sets of twelve pulse converters are then controlled to carry the version of equation (1). This slope of this is modified in the
same current, meaning the ground return path is not used region CX to ensure a stable operating point. The remaining
during normal operation. Mixed LCC and VSC systems are part of the characteristic is a ramp-type VDCL to ensure stable
also possible, Fig. 11. operation of the converter down to low voltages [35]. A ramp
Precise choice of the control scheme is based on reactive type VDCL generates fewer harmonics, less over-current and
power consumption (and its availability) at the AC network at over-voltage, but responds more slowly than the bang-bang
either end, and loss reduction/running cost. Typically the type – it tends to be used with weaker AC systems.
rectifier is assigned current control and the inverter is run on The difference in current between XW and YD’ is referred
so called minimum extinction angle () control to set a DC to as the current margin. Either converter can adjust its current
voltage (where =--u, typically 18 at 60Hz and 15 at order by up to this amount and the system will remain stable
50Hz [35] and u is the angle required to commutate current with the above control scheme. For larger changes, and to
from one phase to another). In practice control design of the ensure coordinated start-up and shut-down,
converter is complex [35] with a number of factors to telecommunications are typically used.
consider: symmetry of valve turn on in steady-state (to reduce It is worth noting at this point that back-to-back schemes
non-characteristic harmonics); robustness to voltage and have much lower nominal operating voltages, since the
frequency variation; ability to minimize risk of commutation distance which DC current is transmitted is minimal. Also
failure; speed of response to set-point changes or disturbances. since both converter stations are co-located, a single joint
Operation at the highest voltage possible to minimize losses is controller may be used.
also desirable. B. Modelling Methods
The first step of the control scheme is to trigger the valves.
For smartgrids employing DC components, multiple design
This was initially done on a per phase basis (Individual Phase
studies are required prior to construction. For AC system
Control, IPC). This has advantages, including simplicity of
studies the dominant low-frequency dynamics are in a time-
control, but can produce non-characteristic harmonics as
frame determined by synchronous generator rotor inertias
control between phases is not balanced. More recently a
[35]. Thus detailed models of the converters are not needed in
controlled oscillator is used to produce a waveform locked to a
these studies and a Thevenin or Norton equivalent circuit may
composite of all three phases (a so-called Phase Locked Loop,
be used with phasor (and load-flow) studies. However the
of which many types exist [37]) in so-called Equidistant Pulse
inherent ‘firewall’ that a DC system provides, means that it
Control (EPC). Pulse Frequency Control (PFC) and Pulse
presents a problem for conventional modelling. The behavior
Period Control (PPC) are subsets of this control method.
of the DC circuit is not inherently driven by the physics based
behavior of the AC system (its angles and voltage magnitudes)
but by the control of the converter. Thus solution of the AC
circuit and DC circuit typically have to be split in many
simulation packages solvers, complicating and potentially
slowing solution. Where multiple AC systems exist, multiple
solutions are required.
Harmonic analysis forms a major piece of any design.
Appropriate filters must be appropriately selected and tuned
for the AC and DC sides. Factors include the amount of
current to be filtered, reactive power requirements, the filter
response characteristics, the peak voltages under transients,
Fig. 12. LCCC HVDC Typically bridge control diagram – rectifier
characteristic - solid line, inverter - dotted line, operating point is at Y fault recovery and the size of the filter (much of the extra size
of LCC compared to VSC is the reactive compensation and
The firing angle of the inverter and rectifier are then varied filtering requirement) [35]. The interaction between filters and
to give a stable operating point based on local station control the station, and filters and the AC network need carefully
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consideration and are undertaken by simulation of the detailed voltage instability, small-signal control instability, harmonic
system or by in effect undertaking a harmonic load-flow – responses, over-voltages) which may lead to commutation
modelling all elements as Thevenin or Norton circuits for each failure in the HVDC scheme [36]. AC series capacitors have
harmonic frequency of interest. Obtaining real data, been proposed to help LCC HVDC operate with weak AC
particularly of the AC network, can be challenging and systems (so called Capacitor Commutated Converters) and
typically a ‘worst case’ locus of network impedances is have been used in two back-to-back projects (Garabi in Brazil-
considered. Argentina, 2002, 2000MW +/-70kV and Rapid City, 2003,
DC side harmonics must also be considered since they can 200MW, +/-13kV).
couple to metallic telephone lines (giving rise to a Telephone Technical developments in recent years for the converter
Interference Factor or TIF limit). They can even couple to have been the replacement of electrically triggered thyristors
metallic structures near to overhead lines through stray by those using laser light to trigger conduction (Light
capacitances, leading to ‘touch voltages’, unless careful design Triggered Thyristors, LTTs). This gives advantages in terms
is undertaken [35]. of circuit isolation for the multiple thyristors used in series in
For detailed studies, time-stepping models are required. A each valve. Current rating of converters is still constrained by
Cigré benchmark model exists [36, 38] of a 12-pulse that of individual devices: while putting devices in series is
monopole with standard filters, line models and control. readily possible, though overvoltage and voltage grading
In addition finite element modelling is required for both components are needed, getting semiconductor devices to
earthing structures of the HVDC system and the electric field reliably share current is problematic.
surrounding the structures themselves, Fig. 13. Particularly for The main development in LCC HVDC has been the gradual
the latest generation of UHVDC systems, the extremely high increase in voltage in order to raise power levels. This
voltage means the design of system components to avoid local required considerable research and development across all
breakdown discharge resulting from inadvertently high fields, elements of the system: transformers, lines/ cables, switchgear
requires extensive study. and the converter, all from a current, fault current and
insulation coordination perspective. Much of this has been
enabled by modern computer simulation and study tools,
particularly for insulation coordination. The impact of
computers is also felt within control – where digital control is
now standard and hot-swap redundancy is typically enabled.

V. VOLTAGE SOURCE CONVERTER HVDC

Voltage source converters emerged from the advent of
suitably powerful self-commutating semiconductor switches in
the late 1990s. Since then they have undergone rapid
development in terms of power and voltage, a factor enabled
by their ability to use much of the hardware (transformers, DC
cables, switchgear) used previously for LCC HVDC.
A. VSC HVDC Hardware

Fig. 13. Finite Element Analysis Model of an Experimental Moving Coil

Actuator in an HVDC Breaker System

C. Technical Challenges
Fig. 14. VSC HVDC converter operating principles
A problem for LCC HVDC is operation with weak
networks, (those with a Short-Circuit Ratio, SCR, i.e. ratio of VSC HVDC synthesizes an AC voltage at its terminals
AC rated power to DC link power, of less than 3). The weak from the DC voltage supplied to it. Initially this used Pulse
AC system may not be able to provide sufficient reactive Width Modulation (PWM): a two-level converter switches
power to the HVDC station and will be vulnerable to voltage rapidly between the voltages at the upper and lower DC
disturbances caused by the HVDC system current (such as supply, Fig. 14. The output is the local time average of this,
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which can be varied sinusoidally. Only higher order switching converter, Fig. 15. More advanced topologies such as the
harmonics need to be filtered, leaving a sinusoidal alternate arm converter and full bridge sub-module converter
fundamental voltage at the point of connection, and drastically have also been proposed, since they offer fault blocking
reducing the AC filter compared with LCC HVDC. capability [44].
Losses at this point were still relatively high (Table I),
compared with LCC converter losses of less than 1% per
converter. In order to reduce this, ABB moved to a three-level
technology, Fig. 14, Table I, using the Neutral Point Clamped
(NPC) topology. Subsequent improvement of two level
converter design and the use of Optimum PWM (careful
switching selection to reduce harmonics and third harmonic
injection to boost DC voltage utilization) allowed a further
reduction in switching frequency and losses.
TABLE I
DEVELOPMENT OF VSC HVDC TECHNOLOGY [42,43]

Technology Year Converter Losses per Switching Example

Type converter frequency Project
(%) (Hz)
HVDC 1997 Two- 3 1950 Gotland
Light 1st Level
Gen
HVDC 2000 Three- 2.2 1500 Eagle Pass Fig. 15. One Arm of a VSC HVDC converter showing a limited number of
Light 2nd level sub-modules.
Gen Diode
NPC Since each phase output voltage is controlled by means of
2002 Three- 1.8 1350 Murraylink
level
‘subtracting’ voltage from the DC rail voltages, instead of
Active switching between the rail voltages, transient voltage
NPC differences can occur between the three-phases which are only
HVDC 2006 Two- 1.4 1150 Estlink
Light 3rd Level
partly suppressed by the arm inductors. These ‘circulating
Gen with currents’ can be controlled by a supplementary controller,
OPWM additional hardware filtering and other methods [45].
HVDC 2010 MMC 1 <150* Trans Bay Most installed VSC HVDC stations use a ‘symmetrical
Plus Cable
monopole’ arrangement where a single converter feeds two
HVDC 2016 MMC 1 <150* S West
MaxSine Link overhead lines or cables, rated at +/-Vdc/2, Fig. 16. This
HVDC 2016 CTL 1 =>150* Dolwin 2 minimizes the insulation requirement with respect to ground
Light 4th and also means the transformer does not need to be designed
Gen to have an appreciable DC offset. Other designs with a DC
offset have been implemented (e.g. Skagerrak 4 [11]), Fig. 11.
In two and three-level designs each ‘switch’ or valve is
made of many series connected IGBTs, which requires careful
control to ensure voltage sharing. In 2010 Siemens proposed a
Modular Multi-level Converter (MMC) design based on the
work of Marquardt [20], and other manufacturers also now
offer similar multilevel products. In the MMC HVDC, IGBTs
are connected in sub-modules which insert or bypass a
capacitor. The inserted capacitors in the upper valve (or arm)
subtract from the upper DC rail voltage (+Vdc/2), Fig. 15, to
(ideally) produce a voltage at the output (point Va). The
inserted capacitors in the lower arm add to the lower DC rail
to also produce Va. Since the total capacitor voltage inserted Fig. 16. Typical VSC HVDC converter station layout (AC filter may be
must balance the DC link voltage, at each switching instant omitted for MMC, and offshore the tap charger is typically omitted on the
transformer to reduce space and maintenance requirements)
one or more upper and lower sub-module(s) are switched and
a staircase waveform is produced, Fig. 14. B. VSC HVDC Control
To balance transient voltages and limit potential fault The VSC HVDC system typically controls the current of
currents, arm inductors as also inserted. In case of a fault, a each phase using the voltage at the converter terminals. Since
fast protection thyristor can bypass the IGBTs and diodes, and the semiconductor switches are self-commutated, providing a
a mechanical bypass switch then shorts out the sub-module. sufficient DC voltage exists, this can continue to operate down
For a DC side fault, an AC breaker then disconnects the to very low AC voltage levels. However the IGBTs have in
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0
essence no overload capability – the output is limited to rated controlled voltage or current sources, and power balance is
current, so fast acting control and current protection is needed. typically used to link the two. Phasor domain models are
In most publications a dq control structure of the converter sufficient for slower systems studies. Most economical of all
current is used. A Phase Locked Loop (PLL) is used to in terms of run-time are pure load flow models.
converter three-phase AC voltages and currents to a two-phase As with LCC a variety of other studies are needed, though
(d and q) DC representation ‘locked’ to the AC network in format these are common with LCC, section IV.B.
voltage. This is then used to control real and reactive power
either in a feedforward structure, Fig. 16(a) or using a power
feedback loop, Fig. 16(b). In practice, except when very fast
control is needed, power control based only on Fig. 16(a) has
drawbacks. As with other feed-forward only schemes it is
substantially more affected by voltage disturbance than
feedback schemes (and except for very strong AC systems,
any change in converter power produces a change in AC
voltage [39]).
idc
vs,abc eabc
PCC P,Q R
Rs Ls L HVDC
Vdc Grid
vabc iabc

PLL
abc dq Converter
 Voltage
Control
vdq idq
vd *
eabc
* 
id   ed*
P* P Controller  k p1 
ki1
 s
id 
L

iq L

iq*  ki1   e*q
 k  
p1
s  vq
*
P* N id* P + K *

D  Kp  i id
- s
1.5vd P Fig. 17 – VSC HVDC Control and modelling hierarchy [40]
(a) Feedforward (b) Feedback
Fig. 16. DQ Control structure of VSC HVDC [39] TABLE II
SIMULATION FIDELITY FOR VSC HVDC [40]
C. VSC HVDC Modelling Model Relative Type of simulation Type of study
Modeling of VSC-HVDC has been the focus of a recent ‘level’ run time
Cigré working group [40]. The hierarchy proposed, Fig. 17, is 1 n/a Full physics based model Sub-module design - Not
suitable for circuit studies.
a useful delineator for modelling: the IGBT switching level is 2 1000 Full detailed models: Detailed studies of faults in
only required if detailed investigation at the level of sub- semiconductors shown by submodules; validation of
module voltage and current waveforms are required. Lower nonlinear characteristics simplified models
3 900 Semiconductors modelled As level 2
level controls (circulating current and capacitor voltage
as switched resistances
controls for example) are only required if the internal 4 30 Detailed Equivalent Detailed studies of AC and
dynamics of the converter are required. If transient Model(DEM)- Norton DC faults close to converter
performance of the converter is required then upper level circuit reduction
controls need to be defined (PLL performance and transient 5 2 Average Value Model – Studies of AC and DC
equivalent voltage or transients – high level
voltage and power control). Dispatch and station controls only current source model control system design /
need to be defined for load flows. harmonics
This then links into the level of modelling fidelity 6A 1.5 Phasor domain models Studies of remote AC and
proposed, Table II. For valve group switching, a type 2 or 3 DC transients
model is required. For lower level controls, at least a type 4 6B 0.1 Simplified phasor domain As level 6A
7 0.01 Load-flow Power Flow
model is used, in which each submodule is converted to an
equivalent circuit and these are manipulated algebraically to In practice Average Value Models (level 5) are used in
speed numerically solution. This is the level used in some real- most transient system simulations, with simplified
time hardware-in-the-loop simulators. Upper level controls representation of the connection transformers (neglecting
can typically be sufficiently modelled with a level 5 control, saturation), and DC cables (lumped parameter pi-section
where AC and DC sides of the converter are modelled by models). However where hardware and software limits of the
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converter control are required, the Detailed Equivalent Model (section VI.B), given the very fast time constants of this. Local
(level 4) of the converter gives accurate and fast performance control needs to be used. For onshore converters at present
for most applications [46]. If fast transients (<10ms) need to some form of droop control is typically used, i.e. real power is
be accurately represented, a more detailed cable model such as adjusted in response to DC voltage, and reactive power is
the Frequency Dependent Phase Model [47] may be adjust in response to AC voltage variation. Offshore the VSC
appropriate, or an equivalent circuit model that more HVDC converter typically sets the AC voltage and frequency
accurately represents the frequency range of study than the and absorbs the real power generated by the wind farm.
cascaded, lumped equivalent pi circuit models [48]. For
transient studies, transformer saturation can play a role and OSC1
696.3 MW WFC2
may need to be included [49].
D. Recent Developments in VSC HVDC SCR: 3.5
DC Line1 DC Line2 WF2
125 km DC Line7
200 km
Most recent developments for VSC HVDC have focused 83.4
150 km
WFC1
on increasing power levels and also on tackling new OSC2
411.6
MW
MW
WF1
applications for which VSC HVDC is particularly better suited DC Line3
125 km
than LCC HVDC: offshore windfarm connection and SCR: 3.5
558.9 MW 745 MW
OSC5

formation of multi-terminal systems. DC Line6

175 km
Offshore engineering of the converter requires ensuring that DC Line4
100 km 858.7 MW SCR: 3.5

environmental controls are suited to operation offshore and OSC3 DC Line5

150 km
754.2 MW OSC4

engineering the solution for low maintenance and the limited

space available in the offshore platform, Fig. 18. This is SCR: 3.5 SCR: 3.5

because the dominant cost is that of the platform rather than Fig. 19. – Seven terminal example VSC HVDC test system with Onshore
the converter, and operation and maintenance costs are Converters (OSC) and Wind Farm (WF) Converters (WFC) Offshore [51]
strongly influence by the cost of transporting crews and parts A. Droop Control Algorithms
to site.
Typical droop characteristics for DC voltage are shown in
Fig. 20. AC voltage against reactive power characteristics may
be similarly drawn. Power or current limits indicate the
maximum that each converter can import and export. The
flatter the ‘droop’, the less the converter allows the DC
voltage to vary. A converter in DC voltage control mode (or
‘DC slack bus’ mode) can be considered the special case of a
‘flat’ droop, Fig. 16(a). The steeper the droop line, Fig. 16(c),
the less aggressively the converter responds to a change in DC
voltage to try and stabilize the DC voltage.

Fig. 18 – Offshore VSC HVDC valve hall [63]

Multi-terminal solutions are better served by VSC HVDC

since a converter station can transition from rectifier to
inverter model by varying the direction of current. For LCC
this would require a reversal of voltage and a (mechanical)
reconnection of the converter station to the DC grid. Solutions
like Nan’ao [24], Zhoushan [25] and the German Ultranet [27]
systems are initial examples of the technology needed.

VI. MULTI-TERMINAL OPERATION Fig. 20. Basic voltage characteristics for MTDC control [50], (a)
slack bus, (b) voltage margin, (c) voltage droop, (d) voltage droop
Since VSC HVDC is well suited to multi-terminal
with dead-band
operation, suitable control schemes need to be developed.
A constant power control can be thought of as the special
In a multi-terminal grid, each converter will be some case of a vertical droop line [50]. Droop control can be used to
distance from the others, typically 100km or more, Fig. 19,
share DC voltage control simultaneously between converters.
otherwise AC would have been used. A central
Alternatively margin control, Fig. 16(b) may be selected to
telecommunication system is not fast enough to control all
stations from a central point for primary or current control determine a range of voltage values over which a converter
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undertakes voltage regulation. The overall goal is to minimize faults and take appropriate actions depending on whether the
the risk of interaction after a large power disturbance and keep fault lies within its protection zone or not. In recent years,
DC voltage at a maximum to minimize losses. A dead-band many different fault detection strategies have been developed.
may be introduced into voltage droop to help achieve this in These strategies distinguish themselves in the use of voltage,
some converters, Fig. 16(d) [60]. An important point to note is current or combined measurements (such as derivative or
the impact of electrical quantity measurement accuracy. 0.1% wavelet methods). They also differ in terms of signal
DC voltage accuracy in measurement at high voltage is processing requirements, the need for communication within
considered very accurate [52]. Particularly for shallow DC the substation or between terminals, and the dependence on
droop lines, realistic errors in DC voltage measurement can knowledge of cable, line and substation parameters. These
different detection algorithms also differ in the types of fault
lead to substantial power excursions unless appropriate actions
(including backup) that can be detected and the time it takes to
are is taken [52].
do the analysis. At this moment, while there several academic
B. Multi-terminal control hierarchy proposals which can identify the fault sufficiently quick, there
The segmentation of control levels proposed in [40], Fig. is still the need to develop an industrial solution.
17, maps well to the levels proposed in [41] for control C. Grounding topology
hierarchy: in an AC system an innermost governor exciter Historically, HVDC systems were built either as an
control is acted upon by primary frequency droop control with asymmetrical monopole or a bipolar configuration, with a
typically a proportional controller type behavior. A slower solid grounding point. These systems are characterized by
secondary power control (PI) in turn acts on this, and tertiary high short circuit currents, without high voltage transients.
(optimal power flow, OPF, dispatch control) affects the With the development of VSC HVDC, the symmetrical
secondary control. In HVDC the corresponding control levels monopole configuration became the new standard. Such a
are: an inner current loop, primary DC voltage droop control, system is grounded using a high impedance ground, which
a secondary power (often PI) loop, and again a tertiary OPF significantly reduces the DC short circuit current in case of a
dispatch control. Significantly though, the primary and inner pole to ground fault, but causes doubling of the voltage on the
loop controls in HVDC, particularly VSC HVDC, are order(s) healthy pole. For future DC grids, the decision on which
of magnitude faster than for AC and this needs to be reflected system will be developed is not clear. Nevertheless, it is clear
in the simulation tools and studies used. that both systems might employ different approaches to
protecting the grid. Furthermore, the protection system should
VII. HVDC PROTECTION retain its efficiency in case of asymmetric operation of a
bipolar grid [64].
At present much work is being undertaken to develop
adequate protection of DC grids. The transients after a DC VIII. HVDC PROTECTION EQUIPMENT
short circuit are one order of magnitude faster than those at the
AC side. Furthermore, the DC current itself is harder to DC breakers exist for lower voltage applications. However
interrupt as there are no zero crossings. the DC current breaking problem is challenging since
simultaneous large currents and voltages must be dealt with,
A. DC fault clearing strategies without the periodic current zero and voltage present in AC.
At the time of writing VSC HVDC systems are still
protected by breakers on the AC side. The size of such A. DC Breakers and LCC
systems is consequently limited in power so that their LCC HVDC has the advantage of a large DC side reactance
complete or temporary outage can be tolerated by the (except in back-to-back stations, which tend to be at much
connected AC system(s). As large links grow, for example as lower voltages) which limits rate of rise of fault current. Such
DC grids arise, this may not be the case. In theory DC HVDC breakers which are used in LCC HVDC are for
breakers could be used on each line, Fig. 19. However this reconnecting a pole, and such systems (such as the Metallic
would be prohibitively expensive at present, due to the cost Return Transfer Breaker) do not need to break full voltage and
associated with currently proposed DC breakers. current simultaneously [36]. The principle challenge is thus
Different philosophies have been approached to manage for VSC HVDC which is also the presently preferred
the fault clearing process in DC grids [64]. One alternative technology for future multi-terminal grids.
[53] would be to use a DC breaker to segment the DC grid into Investigation of a fully-rated DC breaker for LCC HVDC
two sections, the loss of any one of which could be tolerated.
was undertaken on the Pacific Intertie in the 1980’s. The
Another option which has been proposed is to clear the DC
400kV, 2kA device used the negative impedance
through the use of fault-tolerant converters. Such converters
characteristics of the electric arc to set up a resonant circuit
allow containment of the DC short circuit by actively
controlling (reducing) the DC voltage. The short circuit could with passive components, providing a current zero to allow
be cleared using much simpler DC switches or disconnectors, mechanical circuit breakers to extinguish the fault current
after which the DC voltage can be restored quickly. [54].

B. Fault detection in DC grids B. DC Breakers and Multi-terminal VSC HVDC

As the transients in DC systems are much faster, the fault The use of mechanical breakers is however too slow for
detection and clearing process needs to fast enough to identify VSC HVDC. While fault-blocking converters, such as those
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with full bridge sub-modules, could help, they would still IX. ECONOMICS AND POLICY
require that the entire DC network be de-energised. This may
A. Drivers for HVDC
not be permissible for large DC grids.
The DC breaker must be fast. Even with a large current HVDC has received much attention in recent years, not only
limiting reactor, the rate of rise of current in such a situation is because of its technical merits, but because of the advantages
from an economic point of view. HVDC offers specific
such that at present DC breakers would need to operate in
advantages over AC systems. DC systems are specifically
around 2-5ms [55, 56] based on a peak current that DC
advantageous when transferring high power over long
breakers could handle of 10-20kA. In order to obtain such fast
distances, connection of systems using cables and the
operation, solid state switches would need to be used. A connection of asynchronous networks. Different drivers have
purely solid state breaker (with all semiconductor switches in created new opportunities for HVDC. In industrialized
the main path), would require many series devices to provide countries, a liberalization of the energy system increase
enough over-voltage capability, which would result in international trade and a change towards alternative energy
unacceptable conduction losses. sources require fundamental upgrades of the already ageing
C. The Pro-Active Hybrid DC Breaker Concept power system. Furthermore, a strong drive for more cable
connections (also on land) arose, since such systems
A solution is the proactive hybrid circuit breaker concept experience much less opposition and shorter lead times. The
developed by ABB, Fig. 21. Current normally flows through a need for additional transmission is driven by the general
large current limiting reactor, an ultra-fast disconnector policy objectives of having a more reliably, sustainable and
(UFD), mechanical switch and a load commutation switch cost effective energy supply. ENTSO-E has announced in
(LCS). The LCS is made of a relatively few semiconductor 2014 that over 50000 km of new transmission assets are
devices in series and parallel. If a fault onset is suspected, the needed in Europe by 2030, of which 25% would be realized
parallel branch made up of a stack of semiconductor devices using HVDC [66]. In developing nations, high growth rates
(the Main Breaker) can be closed, and the LCS opened. resulted in high increases in electric power consumption and
Current now transfers to the Main Breaker. The UFD can then generation. These new investments require substantial
open under zero current conditions. The Main Breaker can upgrades in the transmission infrastructure. This has led to
quickly extinguish fault current, or transfer current back to the new record breaking installations in terms of voltage, power
normal conduction path if the breaker is not required to trip. and transmission line length for DC systems in China and
This and other circuit breaker concepts are presently under India.
investigation by manufacturers and academia for HV and MV B. Framework for HVDC
applications [57].
The development of HVDC systems needs to be
economically viable, as with any other transmission
investment, and a positive outcome of the cost benefit analysis
is required from the investor point of view. The development
of such systems is therefore strongly linked to the manner in
which the remuneration of such systems is organized
(particularly for links between different countries). This
remuneration either comes tariffs (regulated), comes from
Fig. 21 – ABB Pro-Active Hybrid Circuit Breaker [55] market revenues (merchant) for selling capacity, transmitting
power or from offering ancillary services, or from a mix. The
D. Peculiarities of HVDC Breakers regulatory framework in place has a strong influence on the
A key factor of HVDC circuit breakers is the impact of the risks associated with such investments: appropriate ratings,
DC current limiting reactor. This is a large component which connection points, timing, possibilities to interlink with
must withstand full DC fault current. The addition of this to a existing projects etc. At the current stage, a patchwork of
multi-terminal DC network will also change the effective different regulations exist, often focused on the local, national
cable or line impedance and may negatively impact on level. This patchwork complicates the development of a cost-
stability [58]. Also since the travelling wave caused by the DC optimal transmission system.
fault will be reflected by the fault limiting inductor, this will C. Grid Codes
cause a transient increase of the voltage at the DC breaker [56,
HVDC connections are currently predominantly built by a
59] at the onset of the fault appearance. This causes an initial
single vendor. Such systems will in the future, especially when
faster rate of rise of current than had a terminal fault occurred.
DC grids are concerned, consist of different components from
After several milliseconds, in a terminal fault, current
different manufacturers and with different properties. These
eventually rises to a higher level than a non-terminal fault, as a systems also should allow the connection of new components
result of the lower series impedance, but for those initial few to the system. In order to assure a neutral, multi-vendor
milliseconds, a non-terminal fault can give higher fault system which operates reliably, a number of technical
currents. Since the DC breaker must act within the first few requirements need to be agreed. This agreement or
milliseconds, this means a non-terminal fault can be the worst requirement is described in grid codes. Factors which need to
case fault condition for such breakers. be set in such a grid code are described in [65]. These inlcude
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the steady state operating ranges of the DC grid, allowed [12] Abhay Kumar, Victor Lescale, Urban Åstrőm, Ralf Hartings and Mats
transient over- and undervoltages, the voltage-power Berglund, 800 kV UHVDC - From Test Station to Project Execution,
Presented at Second International Symposium on Standards for Ultra
balancing requirements, the connection requirements of new High Voltage Transmission, New Delhi, India, Jan 29-30, 2009, [online]
components, data exchange requirements, amongst many Available:
others. Considerable work is presently being undertaken to https://library.e.abb.com/public/4f6318cc3d8019a9c1257562003580f5/8
develop a consensus on such grid code requirements 00%20kV%20UHVDC%20-
%20%20From%20Test%20Station%20to%20Project%20Execution.pdf
[13] Lennart Carlsson, Gunnar Asplund, Hans Bjorlilund, and Henrik
X. CONCLUSION Stomherg, Recent and future trends in HVDC converter station design,
Presented in IEE 2nd international Conference on Advances in Power
HVDC technology is a well-proven and economic solution System Control, Operation and Management, December 1993, Hong
to a number of problems in power network transmission. Kong
Many years of successful operational experience are now held [14] ABB, Hallsjon: The First HVDC Light Transmission, ABB company
with both LCC and VSC HVDC. Both technologies are still website [online], Available:
http://new.abb.com/systems/hvdc/references/hallsjon-the-first-hvdc-
developing rapidly, and higher power solutions are being light-transmission
developed by a number of manufacturers. Point-to-point [15] ABB, HVDC References: Gotland HVDC Light, ABB company website
solutions are well understood. Future innovative solutions will [online], Available:
arise to further develop markets for HVDC grids in HVDC http://new.abb.com/systems/hvdc/references/gotland-hvdc-light
[16] ABB, HVDC References: Cross Sound Cable, ABB company website
grids, including common grid codes and HVDC DC [online], Available: http://new.abb.com/systems/hvdc/references/cross-
protection. sound-cable
[17] ABB, HVDC References: Murraylink, ABB company website [online],
ACKNOWLEDGEMENTS Available: http://new.abb.com/systems/hvdc/references/murraylink
[18] ABB, HVDC References: Troll A, ABB company website [online],
The authors would like to thank Dr Damian Vilchis- Available: http://new.abb.com/systems/hvdc/references/troll-a
Rodriguez at the University of Manchester for Fig. 13. [19] J Gerdes, (2011, July), Siemens Debuts HVDC PLUS with San
Francisco’s Trans Bay Cable, Living Energy, vol. 5, pp. 28-31,
Available: http://www.energy.siemens.com/hq/pool/hq/energy-
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operation and control in systems with FACTS and HVDC and

building the transmission system of the future, including
offshore grids and the supergrid concept. He is an active
member of both IEEE (PES and IAS) and
Cigré.

Simon P. Teeuwsen (1976) received his

Dipl.-Ing. degree in electrical power
engineering in 2001 from the University of
Duisburg-Essen/Germany, spending 2000
as an exchange student at the University of
Washington, Seattle. In 2005, he received the PhD degree
from the University of Duisburg-Essen/Germany and was
awarded with the Basil Papadias Award from the IEEE
PowerTech 2005 Conference in St. Petersburg, Russia. Since
2005, he has worked for Siemens as an expert for network
studies in the field of High Voltage DC power transmission in
Erlangen, Germany.

Magnus Callavik (M’11) graded with

M.Sc. (’94) and Ph.D (’98) from the Royal
Institute of Technology in Stockholm,
Sweden. He joined ABB in 1999 where he
is the Vice President and Technology
manager for the Business Unit Grid System
in ABB, which covers the areas of HVDC,
Offshore wind connections, HV cables and
Power Semiconductor at the Power Grids Division. He holds
an Executive MBA from Stockholm School of Economics
(2009) and is a certified project management professional
(PMP) since 2008.