RECOMMENDED VOLTAGES FOR HVDC GRIDS

684
RECOMMENDED VOLTAGES
FOR HVDC GRIDS
JOINT WORKING GROUP
B4/C1.65
APRIL 2017

Members
A. PARISOT, Convenor FR C. JENSEN DK
M. BODEN, Secretary UK J-L. LIMELETTE BE
G. SOMMANTICO, Secretary IT P. LUNDBERG SE
E. ABILDGAARD NO T. MURAO JP
T. AN CN M. SZECHTMAN BR
R. APADA US U. SUNDERMANN DE
C. BARTZSCH DE O. SUSLOVA RU
C. FROHNE DE P. TUSON SA
P. COVENTRY UK P. YANG CN
K.N GANESAN IN B. YUE CN
V. HERNANDEZ ES
JWG B4/C1.65
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RECOMMENDED VOLTAGES FOR
HVDC GRIDS
ISBN : 978-2-85873-387-3

RECOMMENDED VOLTAGES FOR HVDC GRIDS
Page 3
RECOMMENDED VOLTAGES FOR
HVDC GRIDS
Table of Contents
1- INTRODUCTION...............................................................................................................5
2 - ASSUMPTIONS, SCOPE AND DEFINITIONS.....................................................................7
3 - HISTORICAL PERSPECTIVE ON VOLTAGE LEVELS FOR AC NETWORKS.........................9
3.1 - General Trends ..............................................................................................................................9
3.2 - Illustrations in Specific Countries .................................................................................................9
3.3 - AC Voltage standards................................................................................................................16
4 - SURVEY OF CURRENT AND PLANNED HVDC PROJECTS ............................................ 18
4.1 - Drivers for choosing HVDC systems..........................................................................................18
4.2 - Voltage Choices in Existing or Planned HVDC Links Worldwide .......................................19
4.3 - Outlook in Selected Regions......................................................................................................20
5 - CHOOSING DC VOLTAGES FROM THE SYSTEM PLANNING PERSPECTIVE ................. 25
5.1 - Drivers for choosing recommended voltages for HVDC projects.......................................25
5.2 - Benefits of choosing Recommended Voltages for HVDC projects......................................27
5.3 - Conversion of AC to DC..............................................................................................................28
5.3.1 - Relevant aspect to consider for the AC/DC conversion.................................................28
5.3.2 - Analysis of different actions carried out around the world ..........................................33
5.3.3 - Voltage aspects and final considerations on conversion ...............................................34
5.4 - Point to point HVDC without Outlook to evolve to an HVDC grid .....................................34
5.5 Planning a new HVDC system near an existing system...........................................................35
5.6 - Planning of new HVDC system with outlook to evolve into a DC grid ..............................36
5.7 - Operational requirements and selection of the voltage range..........................................38
6 - TECHNICAL CONSIDERATIONS FOR VOLTAGE LEVELS IN HVDC GRIDS .................... 39
6.1 - Definitions of Relevant Voltage Levels and Other Limits .....................................................39
6.1.1 - Definitions in standards, and proposed DC voltage definition ....................................39
6.1.2 – Current practices in point to point HVDC projects..........................................................41
6.2 - Overview of HVDC technologies ..............................................................................................41
6.2.1 - Converter technologies.........................................................................................................42
6.2.2 - HVDC grid transfer capability ...........................................................................................46
6.2.3 - Cable technology ..................................................................................................................46
6.2.4 - Overhead line technology ...................................................................................................49
6.2.5 - DC Compact Switchgear and DC Compact Transmission Line (DC CTL).....................49
6.3 - Relationship between cost and voltage...................................................................................49
7 - UPGRADING OR INTERCONNECTION OF DC SYSTEMS WITH DIFFERENT VOLTAGES 51
7.1 - Upgrading of a DC system to another voltage.....................................................................51
7.2 - DC-DC conversion equipment....................................................................................................52

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8 - TOOLBOX TO CHOOSE DC SOLUTIONS AND VOLTAGE............................................. 54
8.1 - Recommended DC Voltage Levels............................................................................................54
8.2 - Toolbox..........................................................................................................................................56
9 - CHALLENGES TO HVDC GRIDS BEYOND THE STANDARDIZATION OF VOLTAGES.... 58
10 - CONCLUSIONS AND RECOMMENDED VOLTAGES FOR HVDC GRIDS ...................... 60
11 - LIST OF REFERENCES.................................................................................................. 61
12 - APPENDIX: IMPLEMENTATION OF THE FLOWCHART................................................ 63

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1- INTRODUCTION
While High Voltage Direct Current (HVDC) solutions for bulk power transmission have been developed and
implemented commercially since 1954, recent years have seen a strong increase in the number of HVDC projects.
There were about 80 commercial projects rated above 50 kV in the 5 decades until the year 2000, 40 in the span of
ten years between 2000 and 2010, and at present we can expect about 80 new projects in the decade between 2010
and 2020. While in the 20th century, almost all electrical transmission was performed in AC, at present, about 30%
of the planned investment in Europe for new transmission infrastructure will be in HVDC technology (according to
the ENTSO-E ten year network development plan released in 2012).
This trend has been driven by the dual drivers of a changing worldwide context and advances in technology. The
integration of renewable energy requires grid evolution and development to adapt to the changing generation mix
and connect new units to the grid in areas where it was not strongly developed before, especially in coastal areas for
offshore wind or other sea-based resources. The deregulation of the energy sector in Europe as other regions in the
world, has created a strong drive towards market integration in larger areas, hence promoting the development of
interconnectors between price zones. Grids in countries like China, India, Brazil and certain parts of Africa are
expanding rapidly due to economic growth in these countries. These factors and others contribute to a worldwide
need for new electricity transmission infrastructure, and HVDC solutions appear now as suitable options to meet this
need in addition to now “conventional” AC solutions.
At present, almost all existing and planned HVDC transmission systems are point to point schemes. As these systems
increase in number, we can expect a strong rationale for a transition to multiterminal systems, either at design stage
or when new connections are created. Already some VSC multiterminal projects have been commissioned, such as
those on Nan’ao Island and Zhoushan Islands in the Guangdong Province and Zhejiang Province of China
respectively. At a later stage we can also expect, as was the case for early AC transmission networks, a trend to
interconnect and mesh these systems, thus evolving towards DC grids.
As this trend unfolds, early harmonization and standardization of HVDC system parameters and solutions can be
expected to provide key benefits. In this brochure, we tackle the issue of DC voltages, which can be considered the
“most immediate” parameter to be harmonized, with the following expected benefits:
 Limiting the need of DC/DC conversion equipment and associated costs (CAPEX, losses)
 Rationalization of spare parts
 Reduction of maintenance time and improvement of reliability
 Reduction of qualification costs
 Optimization of DC converter and line design, with the subsequent reduction in capital and operating costs
In individual projects, these benefits will be evaluated according to system planning decision processes, even though
the DC voltage levels will no longer be opened as optimization variables for the specific need of a project. One of
the main goals of this brochure is therefore to provide guidance to system planners in making this analysis.
The brochure outline is as follows:
 Chapter 2: The scope and technical terms for the brochure are defined, either directly or using references
to standards or other technical documents
 Chapter 3: A short historical review of harmonization and subsequently standardization of voltages in AC
networks is sketched to provide some context for our work on DC grids
 Chapter 4: Existing and future HVDC projects are surveyed with respect to choosing DC voltage levels
 Chapter 5: The issue of choosing DC voltages in individual projects is approached from a system planning
point of view, highlighting the process and benefits of choosing harmonized DC voltages
 Chapter 6: Technical aspects regarding the choice of DC voltages for given project parameters are
considered, based on the voltage limits for components and taking into account modular approaches
 Chapter 7: Alternatives to an initial choice of harmonized voltages in system planning are studied , i.e.
later interconnection of DC systems with different voltages
 Chapter 8: A toolbox to choose DC system voltages for specific projects has been created and is
presented
 Chapter 9: Other barriers to DC grids than the harmonization and standardization of voltages are
described
 Chapter 10: A set of DC voltage levels for HVDC grids is proposed and recommended

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 Chapter 11: This chapter contains a list of references used in brochure, between brackets, i.e. [reference
number]
 Chapter 12: It is an appendix including the implementation of the high level flowchart proposed in Chapter
8 with mathematic equations and results of case studies

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2 - ASSUMPTIONS, SCOPE AND DEFINITIONS
This brochure serves as a guideline for HVDC projects that might potentially become part of a future HVDC grid.
Two scenarios will be considered for analysis in the brochure as follows:
 Interconnection of two DC systems, here defined in a broad manner (point to point HVDC, multi-terminal,
meshed, etc…)
 New DC connections to an existing DC system
The resulting topologies may not necessarily fit the accepted definition of “HVDC grids” [16, 17]. However, in the
context of this work, the discussion will apply to both multi-terminal HVDC systems and meshed networks, therefore
for simplicity we will use the term HVDC grid to address the both situations.
The scope is limited to steady state pole to ground and steady state pole to pole DC voltages. The emphasis will be
on Voltage Sourced Converter (VSC) HVDC schemes, as large scale meshed HVDC grids are more likely to be
based on such schemes. However, in this brochure, we will also consider Line Commutated Converter (LCC) HVDC
schemes, which in some situations are designed as multiterminal systems or can expand to such systems.
One of the main expected benefits of the present brochure will be to put forward a proposed set of precise definitions
of voltage-related steady state quantities. Indeed, at present, there can be considerable ambiguity regarding the very
notion of “DC voltage” when referring to a HVDC project. An illustration can be given with respect to LCC and VSC
schemes. For VSC projects, the DC voltage can be commonly defined as the voltage of pole to ground, and the
voltage difference is usually small between the two terminals in current projects due to the short transmission line
and low current. For LCC projects, the DC voltage can be commonly defined as the pole voltage to neutral. The real
pole voltage to ground is usually lower than the nominal DC voltage, due to the neutral line voltage drop. At the same
time, there is a voltage difference between terminals is due to the transmission line length and resulting line voltage
drop. These differences highlight the need to carefully review voltage definitions.
Insulation coordination aspects of HVDC grids will not be covered in detail in this brochure.

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Acronyms used in the brochure are defined as follows:
AC Alternating Current
CAPEX Capital Expense
DC Direct Current
DCCB Direct Current Circuit Breaker
DSO Distribution System Operator
EHV Extra High Voltage
HVAC High Voltage Alternating Current
HVDC High Voltage Direct Current
IGBT Insulated Gate Bipolar Transistor
LCC Line Commutated Converter
MI Mass Impregnated
MMC Modular Multi Level Converter
NPV Net Present Value
OHL Over Head Line
OPEX Operational Expenses
PFC Power Flow Control
PPL-MI Paper Polypropylene Laminated Mass Impregnated
PSS Power System Stabilizer
PST Phase Shifting Transformer
PWM Pulse Width Modulation
SM Sub Module
TCSC Thyristor Controlled Series Compensator
STATCOM Static Synchronous Compensator
SVC Static Var Compensator
TSO Transmission System Operator
TTC Total Transfer Capacity
UHV Ultra High Voltage
VSC Voltage Sourced Converter
XLPE Crosslinked polyethylene

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3 - HISTORICAL PERSPECTIVE ON VOLTAGE LEVELS FOR AC NETWORKS
3.1 - General Trends
A survey of the historical development of AC networks reveals that in these networks, the issue of harmonization and
standardization of voltages was also encountered. Illustrations from several countries across the world reveal some
general trends and patterns, which can be very enriching when considering the issue of voltages in DC networks.
Indeed, in many ways, it could be expected that the development of DC networks may follow a similar route.
At the turn of the 20th century, the early AC network development in many countries was characterized by the
emergence of small local systems, typically one or a few generating units feeding an urban area and its vicinity.
These small systems were developed independently from each other and optimized in their design based on the
distance between generation and load and the power transfer requirements. The AC system voltage was one key
parameter in the optimization of the design and was consequently chosen to match closely the system needs, without
any consideration to standardization, harmonization or later interconnection. From an organizational point of view,
the sector was very fragmented, with a large number of small local system operators. In the manufacturing sector,
the technology was evolving rapidly from the early developments in the years 1880-90, which did not provide much
incentive towards a harmonization of equipment and design parameters.
As the system developed further, in the 1920s, the case for interconnection of these small systems started to
strengthen. Larger interconnected systems permitted economies of scale, increased overall reliability through the
meshing of the system and the pooling of generation sources to limit the impact of a scheduled or unscheduled
outage of a unit. However, interconnecting these early systems required dealing with their wide range of operating
voltages, sometimes very close to each other. Several countries launched interconnection programs, which resulted
in the choice of a smaller set of standard voltages, and costly adaptations of the existing assets to match these
chosen values where needed.
This trend continued through and after the 1940s. In addition, technological progress raised the available voltages to
the 300-500 kV range, which corresponds to large networks covering one or several countries, or to long distance
transmission. In the case of networks in this range, the outlook of future upgrades to higher voltages or
interconnection over a wider area was this time considered at design stage. In parallel, the electricity sector was
restructured in many countries around one or a very small number of entities to operate and design the complete
system. In developing countries, the electrical networks were planned from the start using the expertise acquired
through these developments and following the available equipment voltage levels from the suppliers that resulted
from them.
Going through these general trends, which are illustrated in specific countries in the next subsection, we can find
interesting parallels with the expected development of DC networks. It is generally envisioned that DC networks will
be developed in a stepwise manner, from small local systems to multi-terminal then meshed DC networks. As was
the case with AC, there is at present a strong rationale to optimize DC voltages in individual projects. However,
looking ahead, a proposed set of recommended DC voltages may prove very beneficial to anticipate the next stage
when interconnection of DC systems takes place.
3.2 - Illustrations in Specific Countries
France
At present, the voltage levels for the AC transmission network in France are 63, 90, 225 and 400 kV (nominal
voltages). A limited number of 150 kV lines are also in operation.
The first high voltage electrical networks in France were built locally in order to bring electrical power to the main
cities, from thermal generation units in the North-Western regions and from hydroelectric units in the South-Eastern
regions. Until the 1930s, voltages were chosen locally in order to optimize the design based on distance and power
requirements and there were no efforts to rationalize voltage levels. In 1918, there were more than 60 operating
voltage levels from 1 to 60 kV. Networks with voltage levels higher than 100 kV developed in the 1920s, with 220
kV as the highest voltage in operation, however the sector was still very fragmented, with 86 utilities owning
transmission lines rated higher than 60 kV in 1933.

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Efforts to interconnect these networks started at the end of the 1930s. On June 16th 1938, an interconnection
program was launched, with 90, 150 and 220 kV chosen as the target voltage values. At that point, the southern
regions widely used two levels, 150 and 60 kV and in the western part of France the 90 kV voltage level was also
widespread.
After the Second World War, it was decided to upgrade the 150 kV infrastructures to 220 kV, however the process
was slow. The 380 kV voltage level was chosen in the 1970s to constitute the backbone of the interconnected
network as the nuclear program was launched in France.
Italy
The EHV Italian network consists of a set of 380 kV and 220 kV AC lines for transmission over long distances.
Moreover, the HV sub-transmission network - at AC voltage level ≤150 kV - is mainly devoted to the regional power
transmission and to feed MV distribution networks.
As far as the EHV network is concerned, the standard voltages were chosen in the 1960s after the nationalization of
the electricity sector. This was done taking into account both the range of operation of autotransformer available and
the average distance to be covered in Italy, which is in the order of 100-150 km (the longest EHV AC line length is
about 200 km).
The northern area of the Country relies on a sub-transmission network operating at 132 kV while in the southern
regions the standard voltage for the HV network is 150 kV. This difference is basically due to pre-existent standard
voltages adopted by utility companies in charge of the electric service before the electric sector nationalization in the
1950s.
In several regions of the Country, there are still local portions of the sub-transmission network operating at 60 kV,
which were part of distributors’ asset before their inclusion in the TSO’s perimeter. However, in the forthcoming years,
most of the 60 kV infrastructure is going to be demolished or upgraded to 150 kV/132 kV.
Norway
From the beginning, the evolution of Norwegian AC grids was highly affected by the geographical distribution of hydro
power. While most hydro based power systems today have large power plants and extensive transmission networks
between the production and consumption centers, the Norwegian system was based on a large number of islanded
grids with small power plants located close to the consumption areas.
In the first two decades of the 20th century, there were local systems supplying municipalities or small regions, but
no main grid. This structure with short transmission distances did not require high voltage levels, and hence well
proven technology developed abroad was applicable. The interconnection of the utility areas into regional grids
started in the 1920s. The main reason for interconnecting was to gain scale advantages e.g. related to different
consumption patterns.
The development was inspired by interconnections abroad, and Norwegian engineers educated in Germany played
an important part. By the time the interconnection of local utility grids started, the frequency and voltage level were
standardized to a large degree, but the operation voltages varied somewhat.
Up to the Second World War, the Norwegian power system was divided into smaller regional grids with voltages
below 66 kV. The only exceptions were two lines built in the 1920s with respectively 110 kV and 132 kV connecting
large power plants to the distribution system in the Oslo area. In the 1950s, 132 kV and 220 KV became established
voltage levels, and in 1961 the first 300 kV line was built. At this point 420 kV was becoming a standardized voltage
level in Sweden, and in 1963 a 420 kV line to Sweden gave a new record in voltage level in the transmission system.
There are still multiple voltage levels in the regional grids today. In the Oslo area 33 kV, 50 kV and 66 kV are used
in addition to 132 kV.
The fact that 22, 66, and 132 kV are common voltages in the power system dates back to Thomas Alva Edison's
New York system in 1882. A voltage drop of approx. 10 % in the distribution was compensated by choosing voltages
dividable by 11.
The Norwegian Electrotechnical Committee (NEK), was founded in 1912. NEK became the 21st member of The
International Electrotechnical Commission (IEC).

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South Africa
The South African and Southern African transmission systems experienced a similar evolution from multiple isolated
power systems supplying main towns and mines to standardized voltages and centralized, large power stations.
Voltages evolved from 88kV to 275kV to 400kV to 765kV as loads and generation increased in size.
The South African and Southern African transmission systems are characterized by long transmission distances.
Cape Town is 1400km from Johannesburg and the Cabora-Bassa hydroelectric powerplant is 1200km from
Johannesburg. Cape Town connects to Johannesburg at 400kV and 765kV and Cabora-Bassa connects to
Johannesburg at 535kV DC. There are long interconnectors to neighboring countries e.g. Aries Substation (SS) in
South Africa to Auas SS in Namibia which is approximately 1000km long.
In the late 1980’s 765kV overlaid the 400kV transmission system to the Cape and 765kV is currently being
constructed from the large coal-fired generating zone in Mpumalanga to the Eastern or Natal region of South Africa.
United Kingdom
In 1921, there were more than 480 authorized suppliers of electricity in the UK. They were generating and supplying
electricity at a variety of voltages and frequencies. The Electricity Act 1926 created a central authority to promote a
national transmission system. This system was largely completed by the mid-1930s and included the 132kV voltage
level.
The Electricity Act 1947 brought the distribution and supply activities of 505 separate organizations in England and
Wales under state control and integrated them into 12 regional Area Boards. The generating assets and liabilities of
a number of companies in England and Wales were also transferred into a single state-controlled body.
The 275kV Supergrid was established in 1950s. It was constructed with a long term aim to eventually upgrade to
400kV. The Electricity Act 1957 established the Central Electricity Generating Board (CEGB) and the Electricity
Council. Under this act, the structure of the nationalized electricity supply industry in England and Wales (ESI) had
the following features:
 CEGB produced the majority of the electricity generated in England and Wales
 CEGB owned and operated the transmission system and its share of the interconnections with France and
Scotland
 12 Area Boards purchased electricity, mostly from the CEGB, and distributed and sold it to customers within
their designated areas
 Electricity Council exercised a coordinating role for the ESI, providing services in areas of common interest
(i.e: national pay bargaining, certain treasury activities…)
Work began in 1961 on 400kV grid network, which was completed around 1966.
In the 1980s, further changes were made to reduce the environmental impacts of the Electricity Industry, starting the
transition from thermal generation to renewable sources such as wind farms. In 1989, through the Electricity Act, the
UK Government targeted Electricity Industry restructuring to drive privatisation and competition into the Industry:
 Thermal Generation moved to PowerGen and National Power
 Nuclear Power became the responsibility of Nuclear Electric
 Transmission Network and pumped storage became the responsibility of the National Grid
China
Before 1949, the electric industry in china developed very slowly. Between 1908 and 1943, following the demands
of individual and local projects, AC voltage levels were gradually increased from 22, 33, 44, 66, 110 to 154 kV. After
that period, network construction planning was taken into account to form economical and reasonable grid voltage
levels. Each voltage level was designed to meet the power demand for the next 20 to 30 years.

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Before 1981, the 220kV voltage level dominated the Chinese power grid. The following years into the 1990’s saw
500 kV level projects blooming. At the present time, 1000 kV UHVAC network is likely to take shape in China. Also,
the voltage sequence in northeast, north, central, east and south China grid is 1000 kV/500 kV/220 kV.
In northwest China, the 330 kV voltage level was widely used before 2003. However, as power demands keep
increasing, the 330 kV system could not meet the requirements for power transmission, thus a higher voltage level
of 750 kV, surpassing 500 kV, has been introduced and is now in a dominant position in the northwest China power
grid. So the voltage sequence in northwest China grid is 750/330 kV.
Voltages used for several DC Transmissions adopted in China are 500 kV, 660 kV and 800 kV. A 1100 kV UHVDC
project is now moving from planning to execution phase and is planned to be ready for operation in 2018.
Brazil
The high voltage transmission system in Brazil started from the 1940s, with the first 230 kV line to evacuate the
energy from the Paulo Afonso hydroelectric plant.
After 1950 several Federal and State owned companies were formed with the aim of implementing a vast portfolio of
hydro plants. Therefore, new transmission lines were justified. Transmission levels of 230, 345, 440 and 500 kV were
designed. It is also important to highlight that until the 1950s, two operating frequencies, 50 Hz and 60 Hz were found
in Brazil. In the early 1960s, the country decided to unify the frequency in 60 Hz.
In the early 1980s the construction of very large hydro plants such as Tucuruí (8,400 MW) and Itaipu (12,600 MW)
have given room for the implementation of two new voltage levels, respectively, 500 kV and 750 kV, as well as the
first HVDC line rated at ± 600 kV.
Figure 1 shows the historical evolution of the Brazilian transmission system voltage levels.
Figure 1. Evolution of Transmission System Voltage Levels in Brazil
It is also important to see the evolution of the system voltage levels under the new Regulatory Framework
implemented in Brazil since 1998, in which any new transmission asset results from a Concession auction granted
to a Transmission Agent who offers the lowest rental fee (Regulated tariff), for 30 years. Figure 2 shows this evolution.
230 kV
345 kV
440 kV
500 kV
750 kV
600 kV HVDC
800 kV HVDC
0
100
200
300
400
500
600
700
800
900
1954 1960 1971 1975 1982 1984 2014

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Figure 2. Evolution of km of transmission lines in Brazil, through auctions.
* CC stands for HVDC
We can see from Figure 2, the predominance of the 230 kV and 500 kV voltage levels in Brazil, in recent years.
Levels such as the 440 kV are no longer used in new projects; 345 kV very few only. No further project on 750 kV
has been proposed. In a recent HVDC auction (Belo Monte) the selected level was ± 800 kV.
Spain
During the first third of 20th century, the transmission voltage used was increased gradually, starting in 1905 with the
first 50kV power line. In 1909 a line at 66kV was built, in 1913 80kV was reached, in 1914 a 150km 110kV power line
was built, in 1923 was the first time 132kV was used and in 1933 the voltage of 150kV was installed in the grid.
At the beginning the objective of these power-lines was the connection between the production centers and the main
cities. The first attempt to build a national transmission grid was in 1926. In 1944, with the creation of the company
UNESA, we saw the final establishment of a national transmission grid.
During the 1960s and 1970s, the 220 and 400kV transmission grid was developed. Hence, the transmission grid in
1980 was 39964 km long of which 21% is at 400kV voltage, 35% at 220kV and the remaining 44% at 110/132kV.
Figure 3 shows the current figures and evolution of national transmission grid in the last years.

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Figure 3. Evolution of km of transmission lines in Spain.
Nowadays, the transmission grid is formed mainly by 220 and 400kV facilities and the distribution voltages are lower
than 220kV. The preferential voltages levels in distribution grids are 132, 66, 20 kV. It is worth noting that some areas
share grids of close voltages levels (132 and 110kV) for historical reasons, and it is more difficult to manage the
spare parts of the more uncommon 110kV level grid.
India
At the time of independence (1947), power systems in the country were essentially isolated systems developed in
and around urban and industrial areas. The installed generating capacity in the country was only about 1300 MW
and the power system consisted of small generating stations feeding power radially to load centers. The highest
transmission voltage was 132 kV. The state-sector network grew at voltage level up to 132 kV during the 1950s and
1960s and then to 220 kV during 1960s and 1970s.
Subsequently, in many states i.e. provinces (for example - U.P., Maharashtra, M.P., Gujarat, Orissa, A.P., and
Karnataka) a substantial 400kV network was also developed in the State sector as large amount of power was to be
transmitted over long distances. With the development of state Electricity grids in most states of the country, the
stage was set for development of regional grids.
The National Grid consists of the transmission system for evacuation of power from generating stations, the inter-
regional links, Inter State transmission system and Intra-State transmission of the STUs (State Transmission Utilities).
Thus, the development of the national grid has been an evolutionary process. It is expected that, at the end of 12th
Plan, each region in the country will be connected to an adjacent region(s) through at least two high capacity
synchronous 400kV or 765kV lines and a HVDC bipole/back-to-back link. This would make the National Grid a large,

Page 15
meshed synchronous transmission grid where all the regional and State grids in them would be electrically connected
and operating at single frequency.
Figure 4. Evolution of the grid and voltages in India
Russian Federation
Russian Unified Power System (UPS) consists of 69 regional energy systems, which in turn constitute seven united
power grids: East, Siberia, Ural, Mid-Volga, South, Central, and North-West regions.
The process of creating and interconnecting the grid into a unified power system was accompanied by a gradual
increase of nominal voltages of OHLs in order to increase their power transmission capacity.
The first 110 kV OHL in Russia was built in 1922 for power transfer from Kashira power plant to Moscow regional
energy system. The first 220 kV OHL was commissioned in 1933 for power transfer from Nizhne-Svirskaya
Hydroelectric Power Station to Leningrad regional energy system. The 440 kV OH line between Kuibyshev
hydroelectric station and Moscow regional energy system was commissioned in 1956. Then the voltage level of this
OHL was increased to 500 kV with the same OHL dimensions. The 330 kV OHL Baltic power plant - Riga was
commissioned in 1961, the 500 kV OHL Volgograd hydroelectric plant –Moscow was commissioned in 1961, the 750
kV OHL Konakovskaya power plant- Moscow was commissioned in 1967.
UPS of Russia is located on the territory which comprise of 8 time zones. To supply such an extended area required
the widespread use of high and very high voltage levels for long-distance power transmission.
Two scales of rated voltage were historically formed in Russian Unified Power System. The first one, most widely
used, includes the following set of values: 110-220-500-1150 kV, the second one - 110-330-750 kV. The second
scale is used in North-West zone and partly in Central area.
It is estimated that in 2004, the 330-750 kV power system provided transmission and distribution of about 11% of the
total capacity of the country.
The electrical network scheme is developed in such a way as to minimize transformation of 220/330, 330/500 and
500/750 kV.
The total lengths of the OHLs at 110 kV is amounted to 303500 km, 220 kV – 102160 km, 330 kV – 11380 km, 500
kV – 40080 km, 750 – 3570 km.
The basis of the energy transport system of UPS of Russia is the electrical network at 500-750 kV. This is the
backbone and interconnection network, used for power transmission from the largest power plants, and for power
supply of the large load centers.

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3.3 - AC Voltage standards
IEC 60038 defines standard voltages for both AC and DC systems, while IEC 60071-1 applies only to AC systems
in the context of insulation coordination.
Table 1. AC voltage definitions in IEC standards
Standard values are defined for the highest voltage for equipment Um, while a voltage range for the nominal voltages
is provided for systems with Um between 52 kV and 245 kV. For Um higher than 245 kV, the choice of the nominal
voltage used to designate the system is left open. Generally, the nominal voltage is a few percent lower than Um, for
example 380 to 400 kV for a system with Um = 420 kV. The operation range of the system is determined by the
system operator; however, under normal conditions in steady state, by definition, the voltages must be lower than Us
at every point of the system. Conversely, in exceptional situations, following load changes or other system events,
some parts of the system may operate slightly above Us, for a limited duration, until remedial actions are taken to
bring the operating voltage within limits.
The relationship between Um and Us is prescribed in IEC 60071-1, consistently with the definitions. The highest
voltage for equipment is chosen as the next standard value of Um equal to or higher than the highest voltage of the
Quantity Definition (IEC 60038) Definition (IEC 60071-1)
Nominal voltage Un Voltage by which a system is designated. A suitable approximate value of voltage used
to designate or identify a system
Highest voltage of a
system Us
The highest value of voltage which occurs
under normal operating conditions at any
time and at any point on the system. It
excludes voltage transients, such as
those due to system switching, and
temporary voltage variations.
The highest mean or average value of
operating voltage which occurs under normal
operating conditions at any time and at any
point in the system
Lowest voltage of a
system
The lowest value of voltage which occurs
under normal operating conditions at any
time and at any point on the system.
It excludes voltage transients, such as
those due to system switching, and
temporary voltage variations.
Not defined
Highest voltage for
equipment Um
Highest voltage for which the equipment
is specified regarding:
a) the insulation;
b) other characteristics which may be
referred to this highest voltage in the
relevant equipment recommendations.
The highest voltage for equipment is the
maximum value of the "highest system
voltage" for which the equipment may be
used.
Highest value of phase-to-phase voltage
(r.m.s. value) for which the equipment is
designed in respect of its insulation as well as
other characteristics which relate to this
voltage in the relevant equipment Standards.
Under normal service conditions specified by
the relevant apparatus committee this voltage
can be applied continuously to the equipment
Rated voltage Ur (of
an equipment)
The voltage assigned generally by a
manufacturer, for a specified operating
condition of a component, device or
equipment.
Not defined

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system where the equipment will be installed. Depending on environment conditions relevant to insulation, a margin
may be required between Um and Us.
The equipment standard defines the relevant rated voltage and its relationship with Um and the associated standard
withstand voltages. While the rated voltage can be defined to be comparable to Um (for example, with circuit breaker,
usually Ur = Um), its definition may correspond to completely different constraints than Um for other equipment, like
surge arresters for which Ur is determined with respect to phase-to-ground temporary overvoltages.
Figure 5. Continuous voltages in AC systems
Figure 5 summarizes these relationships between the various voltages. Different colors highlight various categories
of defined quantities:
 The highest voltage for the equipment, in red, corresponds to a standard design value for the system. It does
not take into account harmonics, unbalance, measuring tolerances and overvoltages, which also depend on
the design characteristics of the system.
 The rating of equipments and design voltages for overhead lines, in green, is determined to be compatible
with the chosen Um value and associated withstand voltages. Usually, this translates to the relationship Ur ≥
Um; however, as discussed above, the rated voltage Ur may be defined by the relevant equipment standard
in such a way that this straightforward relationship does not apply. In such a case, the equipment standard
must define the applicable relationship.
 Operating voltages, in blue, are chosen so that, in normal conditions, the voltage does not exceed Us, the
highest voltage of the system
 The nominal voltage, in purple, used to designate the system, is usually chosen to be within the operating
range
This approach allows to decouple these various categories, highlighted in differed colors, even if in most cases, for
most equipment, we will have Um = Ur = Us.
Note that, the nominal voltage, within the operating range, was meant to represent the typical voltage at which the
system would be operated; however, to minimize losses, operators seek to operate the system at the highest possible
voltage, by setting the highest operating voltages close to Us. Hence, the typical operating voltage nowadays is higher
than the nominal voltage in most cases.

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4 - SURVEY OF CURRENT AND PLANNED HVDC PROJECTS
4.1 - Drivers for choosing HVDC systems
In the past few decades, HVDC systems have been the best economical and environmentally friendly transmission
technology choice mainly for the following conventional applications:
 Transmitting large amounts of power (>500 MW) over long distances (> hundreds km)
 Transmitting power under water
 Interconnecting two AC networks in an asynchronous manner
 Connecting very weak AC systems with significant transient stability challenges
Furthermore, HVDC systems have been considered as an advantageous solution even for:
 Connecting AC systems with large power angle differences
 Connecting AC system to strong voltage source systems where power would normally find lower impedance
paths with inadvertent power flows
 Bringing large quantity of power into large cities or industrialized load zones where fault levels are already
approaching equipment short circuit ratings
 Power transmission line servitudes parallel to other services e.g. railway lines and pipelines
However, the evolution of the whole power system demands a change in thinking that could make HVDC systems
the preferred solution for many transmission applications.
New technologies, such as the Voltage Source Converter (VSC) based HVDC systems, and the new extruded
polyethylene DC cables, have made it possible for HVDC to become technically and economically viable in many
cases. They have widened the applications of the HVDC into the areas like offshore connections that would be very
difficult with the thyristor-based LCC systems. VSC HVDC systems also allow fast control of four quadrant power
flow, which implies stability improvements, not only for the HVDC link but also for the surrounding AC systems.
In addition, there is no Surge Impedance Loading (SIL) effect for underloaded HVDC lines. Significantly underloaded
HVAC lines and systems require significant inductive compensation and often dynamic inductive compensation in
the form of Static VAr Compensators (SVCs) or STATCOMs to avoid voltage issues in the system operation.
Furthermore, the unbundling of the electric sector in many countries as well as de-regulated power markets has
introduced the energy trading within the electricity sector. According to this, bi-directional power transfers, depending
on market conditions, are even more frequent within large systems operation: HVDC systems enable bi-directional
power flow, which is not always possible with AC systems (two parallel systems would be required).
In the past, when the transmission service was part of a government-owned, vertically-integrated utility, land and
rights-of-way acquisition was relatively easier, and it was mainly done under the principle of “Eminent Domain” of the
State. With liberalization, transmission services are often provided by corporatized, sometimes privatized, entities.
In this context, land and rights acquisition currently determines a significant portion of project costs. Once these
costs are included in economic analysis of HVDC versus AC alternatives, HVDC is often the best techno-financial
option since it requires much less land/right-of-way for a given level of power.
In environmentally sensitive areas, such as national parks and protected sites, the lower foot print of HVDC
transmission systems makes them the only feasible way to build a power link. In addition, the HVDC systems allow
synergies with existing infrastructure (as highways, railways, tunnels, etc.) which could strengthen the public
acceptance of electric infrastructures. HVDC transmission systems using cables in sensitive areas is also more
viable than HVAC cables.
Finally, the above mentioned technical end environmental aspects have made HVDC systems not only suitable for a
wider range of applications – e.g. the connection of off-shore wind and near-shore power plants – but also for meshed

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HVDC systems or grids. Future HVDC grids could compete with or replace HVAC grids, especially in the case of
greenfield networks within developing areas
4.2 - Voltage Choices in Existing or Planned HVDC Links Worldwide
The HVDC and Flexible AC Transmission Subcommittee of the IEEE Transmission and Distribution Committee
maintains a list of existing and planned HVDC projects worldwide. At the time of edition of this technical brochure,
the latest available update [20] is dated March 2013. From this list, one can derive some information of the chosen
voltages in HVDC projects. Note that, as explained in chapter 6, there can some ambiguity regarding the definition
of the voltage of an HVDC system; here no attempt has been made to reconcile the IEEE values with the proposed
voltage definition in this brochure, therefore there can be some discrepancies. The quoted power rating may also
include parallel links, and are therefore to be regarded with caution.
Figure 6. DC voltage vs Power rating for existing and planned LCC systems (as of 2013)
In the chart above, we can see the chosen voltages for LCC systems (thyristor technology in the IEEE database).
The projects are sorted by commissioning date; for projects after 2010, future projects are included, without
consideration or filtering based on project status (under construction, planned, decided, etc…). We can see that,
historically, the chosen voltages were not harmonized; all such projects, with very few exceptions, are point-to-point
links that were not meant to be interconnected later on. For more recent projects (after 2010), we see a trend towards
the emergence of harmonized values in the 400-800 kV range: the 400, 500, 800 kV triplet accounts for over 75% of
the projects in this range.
For VSC projects, a similar chart can be drawn, with updated information on the projects as of end 2015.

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Figure 7. DC voltage vs Power rating for existing and planned VSC systems
For VSC systems (IGBT based), all the listed projects were commissioned after 2000 or are planned to be
commissioned. At this stage, there appears no clear trend yet in harmonization of DC voltages. Some future projects
have been included using information from the HVDC newsletter edited by the University of Manchester, as of
November 2015, but the corresponding data is indicative as the projects characteristics may still evolve.
4.3 - Outlook in Selected Regions
China
From the 1980s, 3 UHVAC (1000kVAC) and 27 DC transmission projects (including 24 LCC and 3 VSC) are
commissioned in China. The great bulk of power is transferred by HVDC projects in China. The increasing
transmission capacity is shown in figure 8 and an overview of HVDC links under operation or construction in China
is shown in figure 9.
Figure 8. Transmission Capacity and Energy Transfer of HVDC Systems from 2006 to 2012

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Figure 9. Voltages for existing and planned HVDC links in China
HVDC projects in China are mainly based on LCC technology, which has already been used for 3 Back To Back
HVDC stations, one ±400kV HVDC project, one ±660kV HVDC project, 12 ±500kV HVDC projects, 7 ±800kV UHVDC
projects (3 are under construction, and one is under planning), one ±1100kV UHVDC projects planned to finish in
2018. At present VSC technology does not have large scale application in China. In State Grid Corporation of China
(SGCC), one ±30kV VSC project and a ±200kV 5-Terminal VSC project have been built, both are located in the East
of China. Meanwhile, a ±160 kV 3-Terminal VSC project is in operation in 2014 in Southern China Grid (SCG).
Because of uneven distribution of natural resources and load demands, (hydro power resource is mainly
concentrated in Southwest China, and fossil energy is rich in Northwest China, while most population and industries
are located in Eastern China), most HVDC lines are constructed to transmit the power from the west to the east and
south, where multi-infeed AC/DC power systems take form. For LCC HVDC, commutation failure problem greatly
harms the system, and challenges power system stability.
Looking into the future, if a DC grid takes shape in China, it may contain both the VSC and LCC HVDC converter
stations which could be called Hybrid DC grid. Therefore, the voltage sequence of China’s DC grid has already
established some common voltage levels, e.g., ±500kV, ±800kV.
South America
HVDC projects in Brazil are mainly LCC type aiming at evacuating large amounts of hydro plants energy production
to the main load centers located very far from the hydropower plants. These large HVDC schemes are:
 Itaipu ±600kV in two bipoles with a total rating power of 6,300 MW, with 890 km of lines; commissioned in
1984.
 Madeira River ±600kV in two bipoles with a total rating power of 6,300 MW, 2400 km of lines, commissioned
in 2013/2014.
 Belo Monte ±800kV in two bipoles with a total rating power of 8,000 MW, 2200 km of lines, to be
commissioned in 2018/2020.
There are other HVDC projects, mainly related to back-to-back schemes, with neighbor countries (Argentina and
Uruguay) and one LCC back-to-back of 2 x 400 MW associated with the Madeira River Project to feed the
local/regional grid.
Figure 10 shows in geographical disposition the three main HVDC trunks of the country with a total of six bipoles.

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Figure 10. Main HVDC trunks in Brazil
Africa
In South Africa, DC transmission systems from the large generating zone in the Waterberg region of South Africa is
being contemplated to connect to the large central and eastern load zones.
In 2012 a 350kV Voltage Source Converter (VSC) Monopole Metallic Return HVDC system with overhead
transmission line was commissioned to interconnect Zambia with Namibia. The Inga (Shaba) to Kolwezi 500kV HVDC
system in the Democratic Republic of Congo (DRC) is the third existing HVDC transmission system in sub-Saharan
Africa. It was commissioned in the 1980s and is being upgraded as of 2016.
Europe
Many HVDC projects are currently included in network development scenarios for European networks in the next
decades. The ENTSO-E Ten Year Network Development Plan (TYNDP), in its 2014 edition, comprises over 20 000
km of HVDC lines and cables to be built in the next ten years in Europe. The main drivers for the HVDC choice are:
 The connection of some offshore renewable energy sources, especially in the North Sea area (but most
offshore connections still being AC);
 The integration of the Iberian peninsula, Italy, the Baltic States, Ireland and the UK with mainland Europe;
 The need to bring power generated far from the consumption to cities and industrialized areas (e.g. wind in
Scotland, wind in the north of Germany leading to the setting up of German corridors, etc.).

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Figure 11. TYNDP 2014 investment portfolio - breakdown per technology (from TYNDP 2014)
Regarding the outlook of an offshore grid, the TYNDP 2014 states that “Submarine HVDC cables in the North Sea
build an offshore grid, even though they are point to point or in a few cases three-terminal devices. More important
offshore meshings do not appear as a pre-requisite by 2030, even for integrating the large amount of RES anticipated
in the Visions.”
Other studies have been conducted regarding the outlook of offshore grids in the North Sea, for example the UK
round 3 study [1] or the NSCOGI study [2]. This concludes that coordinated network development at the horizon 2030
results in higher infrastructure investment cost but that those costs are well compensated by the savings in losses,
CO2 emissions and generation costs.
Longer term studies envision the perspective of a pan-european supergrid using an overlay HVDC network. Among
such studies, one can mention the “E-Highways 2050” project co-funded by the European Commission.
India
As part of the 12th (2012-17) and 13th (2017-22) development plans in India, several new HVDC projects are being
pursued as illustrated in Figure 12.. A new 800 kV multiterminal project is under implementation from Biswanath
Chariali in the Northern-Eastern region to Agra in the Northern region. The target power to be transmitted is in the
range of 6000 to 8000 MW.

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Figure 12. Upcoming projects in India
The Champa – Kurukshetra link will have a voltage of 800 kV and transmit 3000 MW, with the option to upgrade to
6000 MW with parallel converters.
A new 500 MW back-to-back interconnector connects India and Bangladesh, using a DC voltage of 158kV. A new 4
x 250 MW link between Madurai (India) and Sri Anuradhapura (Sri Lanka) will include approximately 90 km of
submarine cable, at a voltage of 400 kV.

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5 - CHOOSING DC VOLTAGES FROM THE SYSTEM PLANNING PERSPECTIVE
In general, new investments in transmission system are decided by TSOs based on specific energy market and
network studies as well as on socio-political drivers. Market studies aimed at assessing the ability of a project to
reduce congestion and thus provide an increase in transmission capacity that makes it possible to increase
commercial exchanges, so that electricity markets can trade power in an economically efficient manner. They
highlight the whole interconnected power system structure, rather than specific operational grid bottlenecks. Taking
into account load and production characteristics including wind and solar profiles and constraints such as flexibility
and availability of thermal units, hydro conditions, they are aimed to assess the variation of social economic welfare
(benefits for consumers, producers, and system management) related to new grid investments. In general, a number
of different scenarios would be studied in order to take account of uncertainties, e.g. variation in wind or solar profiles,
generator forced outages, fuel prices or generator developments. On the other hand, network studies have the
advantage of representing the network flows that would be created by certain generator dispatch and load patterns
[26]. HVDC systems generally improve controllability of the network which is an important feature to be considered
in networks studies for system expansion.
Both types of studies (market and network) are often required to completely assess the benefits of new HVDC
systems. The choice of optimal voltages would certainly help system operators to make more profitable HVDC
investments since capital and operational expenditure would be reduced significantly.
5.1 - Drivers for choosing recommended voltages for HVDC projects
In system planning the following criteria are used when choosing DC transmission voltages:
 Quantity of power transfer
 Transmission distance
 Operational and environmental constraints (including fault levels, prospective short circuit current ratings of
DC circuit breakers, DC stations and other devices)
 Capital costs
 Operational costs (e.g. maintenance costs, etc.)
 System losses
 System Reliability (N, N-1, etc…) and overload requirements
 DC thermal capacity of DC cables and DC transformers
Nowadays, the electricity demand grows according to different rates worldwide: developed countries have slower
growth than developing countries where, in some areas, the electricity demand is expected to be doubled in 5 years’
time. System development planners generally consider the outlook for generation portfolio and demand across the
incoming 10-20 years. The desired DC power level is also dependent on the system requirements from the existing
AC system in case of embedded HVDC systems. If for instance the aim is to eliminate a bottleneck in the AC system,
the power level will have to enable transfer of the underrated capacity in the AC system [27]. The desired DC power
level will be the result of a cost benefit analysis, where income will be weighed against the investment cost. Since
DC current is currently limited to approximately 2000A level for VSC IGBT technology (see chapter 6 below for an
extended discussion on present limits and outlook), without overload capabilities, HVDC voltage selection is very
crucial with respect to the HVDC system power capacity. LCC thyristor-based systems are presently able to operate
with DC currents up to 5000A, with some overload capabilities; however, voltage selection is equally important. In
some HVDC projects, especially for VSC schemes the adopted voltage directly determines the power capacity of the
line or cable. Therefore, there is a strong driver to adjust the voltage level to match the power capacity requirement
as much as possible.
In some projects, the primary driver will be to maximize the power transfer capability, given the available technologies
on the market. For a specific targeted reliability, technologies choices can result in large step increases in cost, for
example going from a monopole to a bipole, or having to use different cable technologies. On the other hand, other
projects will target a specific power transfer range and seek to fine tune other design aspects to improve system
management, losses and other operational costs, or address relevant protection and control issues, stability, etc.
In addition to the power requirement, operational costs and system losses make the optimal voltage level also
dependent on the length of the power link. The transmit distance significantly affects the cost structure of the project
and is therefore important for optimization of different parameters. With a long transmission distance, the cost of
cable or overhead line is a large share of the total project cost and minimizing transfer losses is also a key issue

Page 26
which needs to be taken into account. Hence long transmission distances generally lead to higher transmission
voltages. With a short link, the converter losses are a more critical factor. The cost structure also affects how the
link can be built to accommodate future expansion. If the converter cost is the major expense, the cable or overhead
line might be over-dimensioned without affecting the total cost too much. In this case, the converter capacity may
later be increased. With a long transmission distance, the cost of increasing the cable or overhead line capacity will
change the entire cost breakdown of the project.
Looking at geographic areas, it could be therefore reasonable to think about different standard voltages related to
the specific macro-area (e.g. Europe, USA, Western Countries, Southern African Power Pool (SAPP), West African
Power Pool (WAPP), etc.) similar to what currently happens in AC grids.
On the other hand, planning studies should take into account the expected future evolution of the system. To ensure
resilience of the system requires specific design choices: the question of voltage levels needs to be tackled early in
the design, even at the price of flexibility in optimizing other design aspects of the project. The study of the AC system
history in chapter 3 can provide some insight about this topic, with three expected stages.
 Stage 1: Individual point to point HVDC systems
In this stage, HVDC is used to address specific power transfer or evacuation needs in the system: back-to-
back, offshore connections, long distance transmission, interconnectors, city infeed… Each project is studied
individually, and there is a strong driver to adjust the voltage in order to optimize the cost of the project. The
outlook of multiterminal or HVDC grid expansion is usually considered as remote or uncertain, and may not
be envisaged in studies or decision making.
 Stage 2: Multiterminal systems
In this second stage, the need for a multiterminal configuration is either envisaged from the beginning in
planning studies for a specific project or considered for future expansion from point to point to multiterminal.
In the second case, the VSC technology would be preferable. The system planner would consider connecting
several point-to-point interconnectors or offshore wind connections in a multiterminal system, or tap on an
existing link. The use of harmonized voltage will play a relevant role in the feasibility, implementation and
cost of the project; benefits of using harmonized voltages for equipment design or spare parts will usually
also be considered. If existing links are not using harmonized voltages, voltage upgrading or DC-DC
conversion schemes must be implemented (see chapter 7). At this stage, the possibility of transition to a
multiterminal system, i.e. to make a DC connection into an existing link, will usually be foreseen even when
specifying point-to-point systems.
 Stage 3: Meshed grids
In this third stage, a meshed HVDC network or overlay grid is considered through coordinated planning or a
long term master plan. Voltage selection is an integral part of the planning studies, both in terms of the
structure of the systems and operational benefits of having standardized designs. The meshed grid can also
result from the interconnection of existing multiterminal systems, in which case DC-DC conversion may still
be required. At this stage, the specifications of nearly all systems, including point to point, will explicitly take
into account later expansion of the system, coordinated operation under a wide range of conditions and
connection requirements to the DC system.
Most areas in the world are predominantly at stage 1. India has one LCC multiterminal system in operation but no
long terms plans for an HVDC grid. The European networks are close to stage 2, as new multiterminal systems are
being considered, e.g. the Caithness-Moray HVDC link in the north of Scotland which is envisaged initially as a 2-
terminal link but extensible to include a third terminal. While many studies are proceeding to prefigure future meshed
or overlays grids in Europe, the official planning reference ENTSO-E ten year development plan (TYNDP 2014) does
not yet provide a detailed implementation plan for a future HVDC grid like that of stage 3, despite the fact that projects
for approximately 20.000 km of new HVDC links are included in the Plan. China has two multiterminal systems in
operation or under construction (see, for example [28]), and has been recently including the outlook of meshed grids
in long term planning studies, therefore approaching stage 3.
In order to minimize the replacement of cables or overhead lines, the use of recommended voltage in stage 1 or 2
may be advised in order to make feasible a possible expansion towards stage 3. However, as already noted, such
extensive HVDC grids as envisaged at stage 3 have not yet progressed beyond long-term concepts. At the current
stage of system development, the need for extensive interconnection of HVDC networks is not yet seen. Indeed, in

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contexts such as offshore grids and in the absence of commercially available DC breakers, it is argued by some [29]
that interconnected operation of DC grids would be sub-optimal from the perspective of managing the impact of DC
side faults on AC synchronous areas to which the DC grids are connected.
As part of stage 1, HVDC systems are being commissioned with specific voltages according to individual needs.
Therefore, the choice of recommended voltages for future HVDC projects should take the voltage levels adopted for
the existing projects into account in order to minimize the technical and economic effort required to build future HVDC
grids. Additional benefits will result from harmonization of system and component design with recommended
voltages, as discussed in the next section 5.2. This should of course be evaluated for specific project on case to case
basis so that extra expenditure due to use of recommended voltage is justified.
Along with new DC systems, some DC projects will stem from conversion of AC lines into DC systems. Since AC
grids follow standard voltages, reusing the AC infrastructure with more or less adaptations will result in DC voltages
in discrete ranges. The proposed recommended values for DC voltages should be aligned with these ranges, so that
the DC voltage of a converted line can be chosen among the recommended values. Section 5.3 will review the
literature on AC to DC conversion and discuss this point in detail.
The standard voltages choosing for HVDC grids is affected by the need to ensure the robustness as well as system
stability. Given a certain amount of power to be transmitted through a substation, the number of lines connected to
the higher and lower voltage DC bus, determinates the robustness of the system in case of contingency. Another
limiting factor to consider is the maximum power in-feed loss that can be accepted by the interconnected AC network
[30]. This is mainly depending on the robustness of the AC system, and may vary between different AC systems.
The maximum power in-feed loss is less critical in overlaying DC grids, but a situation where both the AC grid and
the DC grid are overloaded is on the other hand more challenging.
5.2 - Benefits of choosing Recommended Voltages for HVDC projects
The formulation of common voltage standards will be an important aspect of future HVDC grids.
From the system planning perspective, the choice of the best DC voltages will be guided by system requirements
rather than historical and inflexible technical requirements and technologies. System planners should define a set
of base-functionalities, common to a wide range of projects, to be submitted to manufacturers. This approach could
encourage convergence towards widely adopted voltage standards with the benefit of HVDC technology price
reductions.
The main benefits of standardized HVDC technologies are as follows:
Design benefits
If standardized voltage levels are used, HVDC equipment specifications can be partially reused from one project to
another. This makes it easier for system planners to focus their efforts on system and operational aspects, leading
to time-saving in the grid design phase. Lower losses and more efficient designs could be possible at distinct and
well-supported voltage levels.
Voltage standards would need to take into account current HVDC technical constraints e.g. limits of DC circuit
breakers, thermal ratings of thyristors and transistors, control complexity, sensitivity to lightning and other
disturbances, etc.
Maintenance benefits
Standardizing equipment simplifies maintenance as well as spares-holding. Additionally, maintenance technicians
would deal with recommended support processes for a defined type of equipment instead of a wide range of products.
Consequently, an increase in the global reliability of HVDC systems could be achieved.
Economic benefits
Standardization of course results in cost-saving, when economic benefits of scale exist. Development costs are
shared between many projects, so an overall economic benefit could be obtained. Qualification processes of HVDC
equipment can also be standardized, allowing additional cost savings. Moreover, when equipment is standardized,
logistics is simplified. Standardization would provide several economies of scale benefits. Furthermore,

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standardization makes it easier to compare products from different manufacturers in order to choose the best
technical-economic solution
Other issues like transformers transportation at high MVA ratings should be taken into account, along with other
limitations like the temperature rise limit for subsea cables, fields, interactions with other equipment, licensing
restrictions, etc…
5.3 - Conversion of AC to DC
This section will consider the conversion of existing AC overhead lines to HVDC. Since the AC voltages are
standardized, this will translate into ranges of possible DC voltages.
For conversion of AC cables to DC, one can refer to TB 606 [31]. There is no outstanding experience of conversion
of an existing AC cable to DC cable, and since the dielectric stress is completely different from AC to DC, it is not
clear whether this can achieved. However, the design a new AC cable with the outlook to evolve to a DC one could
be considered in the future.
For conversion of AC overhead line to DC, one can refer to TB 583 [15]. It is a complete guide for the conversion of
existing AC lines to DC operation.
5.3.1 - Relevant aspect to consider for the AC/DC conversion
In many recent projects, the time for the erection of an OHL has been largely dependent on permitting procedures.
In some cases it may not possible to build a new OHL because of environmental reasons or public opposition. With
this background, the conversion of an existing AC-OHL to a DC-OHL is a good approach to minimize cost and
erection time when a DC-OHL solution can be advantageous. The feasibility of converting an AC-OHL to a DC-OHL
has been investigated in the past [3, 4]. Due to the higher achievable phase to ground voltage, the transmission
capacity of the converted DC-OHL can be higher than the original AC-OHL [4].
When planning a conversion several aspects have to be regarded:
 Necessity of implementation of a metallic return conductor.
 Re-utilization of components (e.g. conductors)
 Partial or total conversion of an AC-OHL with several circuits
 Cost effectiveness: While AC uprating options will usually be less expensive than conversion per incremental
MW of transmitted power, they will seldom achieve the level of increase possible with conversion to DC; nor
will they ever achieve the benefits DC brings to system operating flexibility. For long distance lines, the cost
of transmitted power through DC schemes is lower than for AC. This is because of better utilization of
insulation and clearances inherent in a line, and because the DC flow can be controlled to take full and
continuous advantage of a line’s thermal capability whereas loading of an AC line may be severely limited
by other system-related factors. However, for shorter lines the advantage in lower cost per km of transmitted
power could not overcome the cost of converter terminals.
 Reliability (N-1): According to the “(N-1)” rule, most systems require that power dispatching is limited to a
level where, following the loss of any one line within the system, no loss of load will result. The loss of any
phase of an AC line results in loss of the entire circuit, while a DC line may be seen as a double-circuit line.
Thus, the loss of a DC pole may still allow transmission of some fraction of its previous capacity by means
of current return options. This capability of “redundancy” differs substantially between the various DC
configurations available for AC-to-DC line conversion. Regulations governing (N-1) rules differ for differing
jurisdictions. Where regulations cite loss of a pole as an (N-1) event, redundancy may be quite important.
Where an (N-1) event is defined to include loss of the entire line, it is not. Where earth return current is
allowed during emergencies, redundancy of some DC configurations will increase. Furthermore, where there
is a need to increase power transfer between two points in a complex AC system, the benefit of converting
one of many lines to DC, may depend more on the short term emergency rating of the DC configuration than
on its continuous rating. This too may affect choice of the DC configuration in conversion of the circuit.

Page 29
 Dynamic response: In some circumstances, the rapid control capability of a DC link may increase the level
of power which can be transmitted between two points in a weak synchronous system which would otherwise
be limited by stability concerns. The presence of DC therefore allows the system to operate at a higher load
angle between sending and receiving points, thereby increasing power transfer in accordance with the well-
known power transfer equation. The DC system can also act to damp system transients.
 Configuration options: Figure 13 illustrates a variety of means by which a single-circuit AC line may be
converted to DC. While, for convenience, each circuit in that figure is assumed to be comprised of a two-
conductor bundle, the same configurations would obviously apply to AC circuits with one or more than two
conductors per phase position. Configurations marked with an asterisk are those for which some change in
conductor or tower configuration would be required.
One right-hand column of Figure 13 shows a very simplified power rating index, Ṗ. This is the DC MW rating
of the converted circuit assuming full thermal utilization of the conductors divided by the DC MW rating
achievable through conversion to a simple bipole configuration energized at a DC voltage equal to crest line-
to-ground AC voltage (configuration b).). This index should be viewed as very approximate since the choice
of configuration and other factors will often affect the DC voltage that can be sustained under DC operation.
The DC voltage may also affect the reliability-limited loading of parallel or contiguous AC circuits.
The second right-hand column of Figure 13 indicates redundancy, R, which is defined as the MW capability
of the circuit with one pole out of service relative to the capability with both poles in service. (Since a fault on
any phase of an AC circuit requires tripping of all phases, redundancy is zero.) It is obvious that redundancy
can be improved in some cases by provision of an earth return path during emergencies or by replacement
of shield wires capable of handling load current levels during emergency periods. Redundancy in Figure 13
is understated by not crediting the line and potentially the terminal for a temporary emergency rating higher
than continuous rating.
Figure 13. Alternative single circuit DC conversions (from [15])

Page 30
With regards to voltage in general, AC transmission line conductors are chosen to minimize investment cost and
energy loss, and then verified to assure performance with respect to corona effects. Clearances are selected with
regard to both lightning and switching overvoltage levels. Both corona effects and impulse overvoltages are related
to the peak level of the AC voltage. Hence, an AC line is designed for peak voltage level, while its power capacity is
limited by the rms voltage level. Thus, conversion to DC gains the ratio between the peak and the rms voltage,
increasing the power capacity per AC phase position by √2. However, normal bipole DC options use only two of the
three AC phase positions while other DC alternatives may use all three.
It is well accepted practice that corona and field effects need to be taken into account when designing new AC and
DC power lines, when uprating the voltage of an existing AC line, or when converting existing AC lines to DC
operation. Furthermore, the phenomena are different for AC and DC lines, which must be considered in the
conversion of AC lines to DC operation. The influence of weather parameters, primarily the effect of rain, differs
significantly between DC and AC lines. The following aspects are to be taken into account:
o Corona effects (Audible noise, Radio interference, Corona loss): When a set of voltages are applied on the
conductors of a transmission line, an electric field, or voltage gradient, appears on its surface. If the conductor
surface voltage gradient is above a certain limit, i.e., the critical corona onset gradient, corona discharges
are initiated. The corona discharges produce several effects, amongst them corona power losses, audible
noise, radio interference, and visual corona. Conductor corona, and hence losses, radio interference and
audible noise, is influenced by several factors, including line voltage, conductor bundle height and
configuration, phase or pole conductor spacing, weather conditions (temperature, pressure, humidity, wind,
rain, etc), and the amount of organic or inorganic matter on the conductors. The audible noise emanates
from the air pressure variations that are caused by the corona discharges, more specifically the streamer
discharges created under positive DC voltage or during the positive half-cycle of the AC voltage. The audible
noise is the result of numerous uncorrelated corona discharges, resulting in a broadband noise spectrum
covering the entire range of audible frequencies. For AC lines, audible noise is at the highest in rain, while
for DC lines, audible noise is lower in rain than in fair weather. In fact, when water droplets are present in a
high AC electric field, several positive streamer discharges will occur during each positive half cycle; in the
case of DC, the repetitive breakdown of air gaps between water droplets and the conductor does not occur.
o Field effects (Electric fields and ions, Magnetic fields): Regarding the effects of the electric and magnetic
fields under DC lines, since the fields are static there are no induction effects as with AC lines. Consequently,
the acceptable field magnitudes are much higher for DC lines.
The electric fields at ground level differ significantly between AC and DC lines. The main difference is that
the electric field under a DC line is enhanced by space charges produced by corona discharges on the
surface of the pole conductors. Electric fields at the ground in the vicinity of AC and DC lines are very different
with regard to their dependence on corona discharges on the conductors: AC lines produce electric fields
that are practically independent of the corona since the ions produced return to the conductor when the
polarity changes. DC lines, on the other hand, produce electric fields that are greatly influenced by the corona
since the entire space between the conductor and ground is filled with ions that reduce the electric field close
to the conductors, at the same time enhancing the electric field at ground level. The static electric fields
produced by DC lines do not produce significant electric fields or currents inside the body to cause biological
effects, consequently, no limits have been recommended by ICNIRP. In absence of other concerns, the
remaining effects of DC electric fields are the ions produced by corona, and their charging effects on body
hair and skin, as well as the resulting annoying microshocks occurring when touching charged or grounded
metallic objects under the line.
Nevertheless, the electric field under a DC line is an important design factor while the magnetic field, being
of the same order of magnitude as the earth’s magnetic field, is insignificant to DC line design.
A summary of possible design limits and targets relevant to DC corona and field effects are presented in Figure 14.
These are limits that serve as a suggestion for converted DC transmission lines proposed for a certain situation, and
therefore may not be applicable in all cases, as local conditions and regulations may vary. The values are therefore
given by way of example only. Further research is required to quantify adequately the effect of humidity on corona
inception, ion current density and ground level electric field.

Page 31
Figure 14. Differences between AC and DC corona and field effects (from [15])
Concerning insulators and mechanical consideration, the operation voltage has an effect on two different parts on
the line insulation, namely the insulator strings (primarily in polluted conditions), and tower and midspan clearances
(accounting for conductor displacement due to wind).

Page 32
When converting an AC line to DC, the requirements for insulators become different. The insulation design of existing
AC transmission lines is generally dominated by the performance with regard to slow-front overvoltages, which
determines the arcing distance of the insulator strings. For a given insulator length, the pollution withstand
requirements are then normally satisfied by selecting insulators with a suitable creepage factor (i.e. creepage
distance per unit insulator length). In DC systems, the slow-front overvoltage levels are rather low, and the insulation
design is often dominated by requirements on pollution performance. In fact, insulator pollution may be an even more
important limit to DC voltage level since more pollution is attracted to insulators energized with DC than with AC.
Corrosion of cap-and-pin insulators is also more severe with DC voltage. In addition, high resistivity porcelain and
glass are required to accommodate constant DC voltage. Thus, any scheme for converting AC lines for DC operation
presumes a change-out of AC insulators for DC units. Conventional ceramic and glass insulators for DC (Anti-fog
cap-and-pin insulators) have special properties with regard to corrosion protection and electrical characteristics of
the insulating materials. Composite long-rod insulators made of Hydrophobicity Transfer Materials (HTM) have
generally better pollution performance in comparison with ceramic or glass insulators of the same length. Considering
that the insulator length may be restricted to that of the original AC insulators in order to retain existing air clearances,
composite insulators may be the preferred choice for conversion.
There is a wide range of possible options for line configuration adjustments and the optimal selection are very much
project and site specific. Reinforcement of present structures might be required because of present conditions and/or
because of relevant change of mechanical loading conditions. The largest increase of loading will be due to
introduction of larger conductors and the likely increase in attachment height of the conductor. The condition of
existing foundation is a starting point. When the actual load capacity is established, a necessary level of intervention
on foundation can be developed. Reconductoring is required either because of bad state of existing conductors, or
the need to increase current loading capacity. When the main motive is to increase current rating, it can be done
either with larger standard conductors (ACSR or AAAC), or with novel HTLS (High Temperature, Low Sag
Conductors). A change to standard conductors will be the regularly preferred option, if the strength of supporting
structures allows it, due to its cost effectiveness. A change to the HTLS type, keeping diameter and weight to similar
level as the existing standard conductor, will be the preferred option when the increase of size of standard conductor
will require too costly and/or too time-consuming intervention on present supporting structures. To maximize the use
of existing phase conductors, it may be beneficial to rearrange individual subconductors, e.g., to form a triple-
conductor bipole out of three twin-conductor bundles.
If a metallic return conductor is not necessary, then the conductors of the remaining AC phase can be used to
reinforce the DC conductors (e.g. conversion of 3 four-bundle conductors to 2 six-bundle conductors) without
exceeding the mechanical strength of the tower [5]. In cases where the conductors and the connections points of the
conductors are kept unchanged after the conversion, the conductor surface field gradient and the ground-level field
strength has to be regarded. If the conversion of the AC-OHL to a DC-OHL is only partly (e.g. conversion of one AC-
circuit of a double circuit AC-OHL) the interaction between the AC- and DC-system has to be regarded.
There is a wide range of possible modifications, from small interventions or extension of cross arms up to a complete
change from the tower base. A substantial change to the insulator arrangement is shown in Figure 15. Insulated
cross arm solution as a re-design or change of tower top geometry is an attractive option, which gives a high freedom
of optimization of pole geometry and insulation performance. A major challenge in an upgrade like that is to establish
the integrity and strength of tower body and to re-check tower strength for its actual limits.

Page 33
Figure 15. Transformation of double circuit 220 kV AC to 400 kV DC (from [15])
The cost of structure modifications depends on the following:
o Dismantling and removal from site of existing tower top;
o Fabrication, supply, and erection of new tower top;
o Reinforcement of mainly leg sections.
In the example shown in Figure 15, 40 to 60% of the existing structure has to be replaced, and the cost of replacement
has to be calculated on this basis. The reinforcement of leg sections can mostly be done while the line is in operation
and thus has a small cost implication from line outage during construction. The cost of dismantling and removal of
steel from site can be partially offset by the sale of the removed steel. It is estimated that the cost of towers for new
DC line (material + labor) will be in the range from 20 to 25% of total construction cost.
5.3.2 - Analysis of different actions carried out around the world
Several case studies and references [3,4,5,6,7] have been reviewed with respect to the achieved DC voltage as a
result of the AC to DC conversion.
In addition, the German projects to connect the northern to the southern region via HVDC-links have been considered.
One of these links should be realized by conversion of one 380kV-AC-circuit of an existing OHL into a HVDC-circuit.
With respect to this project several investigations were performed. One investigation shows that it is possible to
convert a 380kV-AC-circuit to 400kV-DC by re-utilization of conductors and their connection points without exceeding
the requirements for the conductor surface gradient and ground-level field strength [8]. In another investigation the
coupling between AC and DC circuits was examined [9]. This investigation shows that there is an ohmic coupling
between AC and DC circuits due to the transport of ions. The current density in the AC circuit is dependent on the
weather condition; especially during heavy rain the current density reaches its maximum. The amount of DC current
is also dependent on the coupling length of AC and DC circuits and can influence magnetic components such as
transformers.
Using these 7 references and the 16 associated case studies as a basis, we can obtain a good overview of the
worldwide experience in this area. It turns out that the obtained DC voltage levels can vary considerably depending
on the line modifications to be made:
o None: No changes are made in the existing line.
o Low: insulator replacement, increasing height of towers.
o High: other higher impact changes to the line (conductors, modification of tower, insulating crossarm, ...)

Page 34
AC line
modification
Ratio DC-AC Voltage.
(pole to grd. DC kV / AC ph-
to-ph kV)
Change in transmission
capability compared to
AC
General comment
None 0.43 Decrease by ~ 50%
The main driver would be
system considerations
(reliability performance,
etc..)
Low
From 0.68 to 1.16 (average
about 1)
Increase by ~50% The main driver would be
increasing the
transmittable power
High
From 1.33 to 1.85 (average
about 1.7)
Increase between 1.5 and
3 times the AC power
The main driver would be a
substantial increase in the
transmittable power
The project/outage
duration may be a few
years
Table 2. Ratio between AC and DC voltages following conversion to DC
5.3.3 - Voltage aspects and final considerations on conversion
Drivers for conversion of an AC line into a DC one may differ from those used in HVDC greenfield projects. Increasing
the amount of transmittable power by an existing AC line– compared to building an additional AC line – represents
the main driver in most of the cases. The advantages in terms of lower environmental impact as well as reduced
construction time could be extremely significant. However, overall system considerations – such as the need for
controlling power flows between two system areas or improving the system stability, as well as provide better
performances than the existing AC line (for instances less losses) – could lead to a DC conversion even if the
increase in terms of transmittable power is poor or absent.
Starting from the existing AC line voltage, the final DC voltage should be decided taking into account the benefit
expected from the AC-DC conversion such as the transmittable power desired. However, wider considerations may
lead to choose one of DC standard voltages if there is the perspective for the converted line to evolve in a
multiterminal or to be connected into a grid. If the converted DC line is conceived to operate as a stand-alone system,
the choice of voltage could be optimized for the single application.
The cost of conversion depends on the works required for the specific power lines. Although the transmittable DC
power would increase up to 3 times the starting AC level, replacements or massive reinforcements of towers would
certainly be quite expensive. Furthermore, additional local authority permissions could be required with consequent
longer construction time. Conversely, when reduced modifications of existing infrastructures – such as insulators
replacement – are sufficient to reach the desired transmittable power target (about 50% of transmittable power
increase), a good cost-benefit ratio could be obtained. It is clear that the cost of conversions also depend on the
conditions of the existing AC power line: very old power lines could require higher investments.
Finally, the conversion of an existing AC cable to DC cable is not recommended since the dielectric stress is
completely different from AC to DC. However, designing a new AC cable with the outlook to evolve to a DC one could
be considered in the future.
5.4 - Point to point HVDC without Outlook to evolve to an HVDC grid
In this case, there is very little rationale to use one of the recommended voltages from a system planning perspective.
Still one benefit is the use of standardized equipment and optimized spare part holding. This situation also applies to
back-to-back HVDC systems.

Page 35
Overall it is recommended to optimize the voltage for the specific needs of the system, taking into account equipment
and maintenance costs. The optimal voltage may differ from the recommended values.
5.5 Planning a new HVDC system near an existing system
This section will consider the case of planning for a new HVDC system in the vicinity of an existing HVDC system
with the outlook of possibly interconnecting the two systems at a later stage. The existing HVDC system A is built
with a DC voltage UA. The system planner will have to choose the DC voltage UB for the new system B, either by
optimizing UB without taking into account UA or by choosing UA=UB. If UB is not chosen equal to UA, the interconnection
of the two systems will imply the use of DC-DC conversion equipment or upgrading of system A or B (cf. chapter 7).
Figure 16. Planning a new HVDC system near an existing system
Choosing the proper voltage for system B can be done considering the following options, which imply different pros
and cons. This is primarily relevant for stage 2.
Planning a new HVDC system should be done considering:
Advantages of grid interconnection:
 Reliability of DC grids
 Optimization of power flows in both DC and AC grids
 Flexibility in providing/absorbing reactive power to AC grid (more than a single point-to-point VSC link)
 Stability of power system (control AC system power oscillation damping)
 Interconnection of AC asynchronous systems (two or more)
Cost of interconnection of HVDC systems:
 Cost of modification of control system for all converter stations (about 10-20% of the capital cost of the
converter station). A “modular” control system may be beneficial to optimize this cost and facilitate the
development of HVDC grids
 Cost of DC/DC converter stations (in general, 2 DC/DC converter stations, depending on the case)
Four strategies can be considered:
1. UB=UA

Page 36
PROs
 No additional cost for DC/DC converter stations
CONs
 The voltage for the new system B (UB) is not optimized. This could give increased capital cost (cost
of equipment) and operational cost (cost of losses)
2. UB≠UA : interconnection by using a DC/DC convertor stations
PROs
 Optimized choice of voltage for system B (UB) so capital and operational cost are minimized
CONs
 Additional cost for DC/DC converter stations (back to back or chopper solution)
3. Optimize UB and then update UA to get UA=UB
PROs
 Optimized choice of voltage for system B (UB); the advantages of optimizing UB increase
proportionally with the size of UB (less capital costs and less operational costs)
 Avoid the use/cost of DC/DC converter stations to connect system A and B
CONs
 Possible high impact/cost for system A; the cost for system A could be sustainable if system A is
very small compared to system B as well as if system A is realized with a very old technology
 If system A is already connected to other HVDC systems, this solution is not applicable as the
change of UA affects also the systems connected to system A;
4. Optimize partially UA (according to the limits of existing equipment in system A) and then select UB=UA finding
a breakeven point between the original UA and the optimal UB for stand-alone operation
PROs
 Avoided the use/cost of additional DC/DC converter stations to connect system A and B
 Reduced impact/cost for the system A (optimization of existing asset if possible) compared to
solution 3
CONs
 Neither the voltage of system A (UA) nor the voltage of system B (UB) are completely optimized, so
a part of the benefits are lost in both the systems proportionally to the size of UA and UB (less both
capital costs and operational costs compared to a not-optimized choice of UA and UB);
 This solution is applicable only for small differences between the optimal voltage values for system
A and system B
5.6 - Planning of new HVDC system with outlook to evolve into a DC grid
This section will consider the case of long term planning for several HVDC systems in a given area, with the outlook
of interconnecting these systems at a later stage to form an HVDC grid. In this context, there will be a strong rationale
for choosing recommended voltages for each system. This is primarily relevant as part of a coordinated long term
planning (stage 3, Chapter 5.1).

Page 37
Figure 17. Planning a new HVDC system with outlook to evolve to a DC grid.
We assume that we are going to build a new HVDC system B in the vicinity of an existing HVDC system A in year n,
with the outlook to connect systems A and B in year n+10. The choice of voltage for HVDC system B could be made
considering the following options, which of course imply different pros and cons.
1. Choose UB=UA but do not account for possible interconnection in the design of system B
PROs
 No additional cost for DC/DC converter station
CONs
 Voltage for the new system B (UB) is not optimized. This could give increased capital cost (cost of
equipment) and operational cost (cost of losses)
 Possible work/investment at year n+10 to connect system B with A, mostly related to the upgrade of
the control system of both A and B
2. Optimize UB for the operation as a standalone system (from the year n to the year n+10, UB≠UA) but plan for
interconnection at a later stage
PROs
 Somewhat increased initial cost in year n for designing system B to be connectable to system A in
year n+10 (cost of more adaptable control, etc.)
 Lower operation cost for system B for year n to year n+10
CONs
 More work/investment at year n+10 to connect system B with A, since converter stations may be
required to connect A and B or changing UA or UB
3. Optimize UB for the operation of system B as part of a HVDC grid (UB=UA from year n to the entire lifetime)
PROs
 System B is already optimized for the interconnection with systems A at the year n+10, so reduced
cost for connecting system B with system A at year n+10
CONs
 Additional cost for in terms of capital costs system B if choosing a higher UB (compared to the voltage
required by the optimal design as standalone system of B) or if choosing a lower UB, in terms of
operational cost.
 Assuming that system A and B have the same lifetime, a possible need of upgrade of system B at

Page 38
the end of the lifetime of system A (sometime after year n), resulting from a displacement between
the lifetime of system B (built at year n) and the lifetime of system A ( built before year n)
5.7 - Operational requirements and selection of the voltage range
In addition to choosing a DC voltage level, the system planner will have to provide input for the system designer in
order to address the selection of voltage operation range. Indeed, as will be discussed in detail in chapter 6, the
minimum operation voltage of the system is also an important design parameter.
For both LCC and VSC systems, not only the maximum continuous design voltage should be specified, but also the
operational voltage range including a minimum continuous design voltage in order to design the equipment to comply
with all operational modes and load flows needed for the project. The main parameters that should be considered
are the converter transformer tap ranges, IGBT and reactor ratings, converter losses and maximum DC current
flowing through the overhead line or cable.
The operating voltage range is expected to be in the range of 5% to 10% of the maximum design continuous voltage.
The range is determined so that required power flows are possible in the HVDC grids, also ensuring stability of the
converter controls.
The DC voltage operating range might be larger for grids with large distances. However, economical as well as other
technical criteria may require voltage operating bands not exceeding 10%…15%. Indeed, an operating band of 10%-
15% leads to an equivalent percentage increase in current for the same power transmission. As losses are in square
of current, this implies line loss increase by 20 - 30%. This has a large impact on operational costs and may be quite
detrimental in terms of utilization of assets.

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