planning and operation of the north sea grid
TRANSCRIPT
i
HubNet Position Paper Series
Planning and Operation of the
North Sea Grid
Title: Planning and Operation of the North Sea Grid
Author(s): Oluwole Daniel Adeuyi, Jianzhong Wu, Jun Liang, Carlos Ugalde-Loo
and Nick Jenkins.
Author Contact: [email protected]
Version Control: Version Date Comments
1.0 16/07/2015 Draft version for peer review
1.1 14/03/2016 Revised in response to peer review comments
2.0 05/05/2016 Final version for publication
Status: Published
Date Issued: 05/05/2016
Available from www.hubnet.org.uk
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CONTENTS
About HubNet.............................................................................................................................iii
1. INTRODUCTION ................................................................................................................ 1
1.1 North Sea Grid Proposals ........................................................................................... 1
1.2 Drivers for Development of Offshore Grids in the UK ................................................ 1
1.3 Submarine Cables....................................................................................................... 3
1.4 Opportunities for UK Research and Innovation .......................................................... 4
2 TOPOLOGIES OF THE NORTH SEA GRID ..................................................................... 6
2.1 Submarine Electrical Power Systems......................................................................... 6
2.2 Status of HVDC technology ........................................................................................ 6
2.3 National Strategies ...................................................................................................... 8
2.4 Development of Electricity Interconnectors in the North Sea..................................... 9
2.5 Visions of the future North Sea Grid ......................................................................... 10
3 OPERATION OF THE NORTH SEA GRID...................................................................... 11
3.1 Physical Structure of VSCs ....................................................................................... 11
3.1.1 Converter Bridges .................................................................................................. 11
3.2 Operating Characteristics of a VSC .......................................................................... 12
3.3 VSC Topologies ........................................................................................................ 13
3.4 HVDC Configuration and Operating Modes ............................................................. 17
3.5 Multi-Terminal HVDC Systems ................................................................................. 20
3.6 Modelling and Testing of MTDC Grids...................................................................... 24
3.7 Potential Interactions between HVAC and HVDC systems ..................................... 24
4 OVERVIEW OF SUPPORT FOR THE DEVELOPMENT OF THE NORTH SEA GRID . 26
4.1 Regions ..................................................................................................................... 26
4.2 National ..................................................................................................................... 27
4.3 European ................................................................................................................... 29
5 Summary........................................................................................................................... 32
5.1 Research Opportunities ............................................................................................ 32
5.2 Conclusions ............................................................................................................... 32
APPENDICES .......................................................................................................................... 33
REFERENCES......................................................................................................................... 46
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About HubNet
HubNet is a consortium of researchers from eight universities (Imperial College and the
universities of Bristol, Cardiff, Manchester, Nottingham, Southampton, Strathclyde and
Warwick) tasked with coordinating research in energy networks in the UK. HubNet is funded by the Energy Programme of Research Councils UK under grant number EP/I013636/1.
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Design of smart grids, in particular the application of communication technologies to the operation of electricity networks and the harnessing of the demand-side for the control and optimisation of the power system.
Development of a mega-grid that would link the UK's energy network to renewable energy sources off shore, across Europe and beyond.
Research on how new materials (such as nano-composites, ceramic composites and graphene-based materials) can be used to design power equipment that are more efficient and more compact.
Progress the use of power electronics in electricity systems though fundamental work on semiconductor materials and power converter design.
Development of new techniques to study the interaction between multiple energy vectors and optimally coordinate the planning and operation of energy networks under uncertainty.
Management of transition assets: while a significant amount of new network equipment will need to be installed in the coming decades, this new construction is dwarfed by the existing asset base.
Energy storage: determining how and where storage brings value to operation of an electricity grid and determining technology-neutral specification targets for the development of grid scale energy storage.
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Planning and Operation of the North Sea Grid
1
1. INTRODUCTION
The North Sea Grid is a concept that is intended to facilitate the transfer of power generated
from offshore wind farms installed in the North Sea to land, interconnect the grids of adjacent
countries and encourage the creation of a European internal electricity market. This HubNet
Position Paper on the North Sea Grid follows a workshop titled “Planning and Operation of the
North Sea Grid”, which took place in Glasgow during HubNet Smart Grid Symposium in
September 2014. The aim of the workshop was to take the opportunity afforded by the annual
HubNet Symposium to consult attendees from UK industry and the academic community on
the research gaps and opportunities offered by the North Sea Grid. The Position Paper
describes the proposed North Sea Grid, reviews the basic principles of high voltage direct
current (HVDC) transmission, highlights potential opportunities for UK research and innovation
and complements the technical annex of National Grid’s Electricity Ten Year Statement.
1.1 North Sea Grid Proposals
Several proposals of the North Sea Grid concept exist in the literature. The Airtricity
Foundation Project [1] proposed 10 Gigawatts (GW) of offshore wind farms to be connected
to the grids of the UK, Germany and the Netherlands. Greenpeace [2] reported that about 65
GW of offshore wind capacity could be connected to the grids of 7 countries around the North
Sea. The Friends of the Supergrid (FOSG) proposed to develop the North Sea Grid in phases
[3]. The first phase is to integrate 23 GW of offshore wind capacity from the UK, German and
Belgian offshore wind farm clusters into the grids of 4 countries (the UK, Germany, Belgium
and Norway). The European Network of Transmission System Operators for Electricity
(ENTSO-E) [4], estimated that 33 GW of offshore wind capacity will be installed in the North
Sea by 2020 and 83 GW by 2030. In 2010, ten countries (Sweden, Denmark, Germany, the
Netherlands, Luxembourg, France, the UK, Ireland, Norway and Belgium) signed a
Memorandum of Understanding to develop an integrated North Sea Grid and formed the North
Sea Countries Offshore Grid Initiative [5].
The proposed North Sea Grid would use both high voltage direct current and high voltage
alternating current for submarine electrical power transmission. HVAC transmission is mature
and well understood. HVDC has better control capabilities, reduced asset footprint and lower
power losses. In addition, HVDC can interconnect power systems operating at different
frequencies and phase angles. At transmission distances typically beyond 80 km and at
transmission voltages typically above 150 kilovolts (kV), HVAC is not practical due to the
capacitance and hence charging current of the submarine cable [6].
1.2 Drivers for Development of Offshore Grids in the UK
The key drivers for the development of offshore grids in the UK are renewable energy targets,
the offshore transmission owner regime, electricity interconnection targets and electricity
market reforms (EMR).
1.2.1 Renewable Energy Targets
The UK Government has set a target for 15 percent of the UK’s energy needs to be met from
renewable energy sources by 2020 [7]–[10]. Electricity generated from offshore wind is
important to achieving this renewable energy target. At present, the UK has about 4 GW of
offshore wind capacity [11]–[13] and this is set to increase to about 9 GW by 2020 [14]. The
Offshore Wind Cost Reduction Task Force reported that about 40 per cent reduction in the
cost of offshore wind energy was possible by 2020, through improved technology, more
industry alliances, and supply chain development [15].
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1.2.2 Offshore Transmission Owner Regime
The Offshore Transmission Owner (OFTO) regime was established in 2009, by the Office for
Gas and Electricity Markets (Ofgem), to deliver transmission infrastructure to connect offshore
generation, at an affordable cost to consumers, and attract new investors to the sector. At
present, Great Britain (GB) has about 4 GW of HVAC offshore wind transmission capacity
through 13 OFTOs [16]. A summary of the concluded OFTO tenders is included in the
Appendix A. It is expected that the first GB HVDC offshore wind transmission connections
could be installed by 2018 and rated up to 1.2 GW [17]–[19].
1.2.3 Electricity Interconnection Targets
The EU has set an electricity interconnection target for 10 per cent of the total electricity
generation capacity in each country to be provided from interconnectors by 2020 [20]. GB
Electricity interconnectors use HVDC submarine cables to connect the GB grid to
neighbouring countries for energy trading and balancing. At present, GB has 4 GW of
electricity interconnections through four interconnectors – 2 GW to France (through the
interconnector known as IFA), 1 GW to the Netherlands (BritNed), and two cables of 500 MW
each to the Irish grid (Moyle and East-West) [21]. This represents about 5 per cent of the UK’s
electricity generation capacity [22]. Figure 1 shows the existing and proposed electricity
interconnectors in the UK.
There are eight new interconnectors proposed to five countries (France, Belgium, Denmark,
Norway, and Republic of Ireland). The proposed interconnectors would have a total
interconnection capacity of about 9 GW and help the UK to meet the interconnection targets.
Also, two embedded HVDC links - Western Link and Eastern Link – are planned to increase
the power transfer capability across the Anglo-Scottish boundary of the GB transmission
system. At present, the Western HVDC link is under construction. It will have an installed
transmission capacity of 2.2 GW and increase the power transfer limits across the Anglo-
Scottish boundary from 2.55 GW in 2015 to 3.9 GW by 2017 [6], [23]. The proposed Eastern
link would have an installed capacity of 2 GW and is planned for implementation beyond 2021
[24].
Figure 1: Map of existing and proposed GB electricity interconnector project [26]
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1.2.4 Electricity Market Reforms
The UK’s Electricity Market Reform (EMR) is designed to decarbonise electricity generation,
increase security of electricity supply and minimise the cost of electricity to consumers. The
two main regulatory mechanisms under the EMR are the Contracts for Difference and the
Capacity Market [11], [25]. Contracts for Difference (CfD) is intended to provide certainty and
stability of revenues for large renewable generation through a 15-year contract period at a
guaranteed price. The Capacity Market is a mechanism that is intended to offer all electricity
capacity providers (new and existing power stations, energy storage schemes, demand side
response and interconnectors) a steady, predictable revenue stream on which they can base
their future investments [11], [26], [27]. In return for this revenue, capacity providers must
deliver the energy required to meet demand when needed or face penalties. In summary, there
is a strong regulatory encouragement for UK participation in the North Sea Grid.
1.3 Submarine Cables
The two functions of subsea cables in offshore wind farms are for the subsea array cables and
subsea export cables. Subsea array cables collect the power generated from offshore wind
turbines. Array cables operate at a voltage of 30 – 66 kV AC and connect offshore wind
turbines to offshore substations. The transformers of the offshore AC substations step up the
collection voltage from 30 kV to a high voltage of 132 kV and above.
Subsea export cables transfer the power from offshore wind farms to land using HVAC or
HVDC transmission. HVAC subsea export cables connect offshore AC substations to onshore
AC substations or HVDC networks. They use three-core cables with cross-linked polyethylene
(XLPE) insulation. HVDC subsea export cables connect offshore converter platforms and
onshore converter stations of the HVDC networks. The two designs of HVDC subsea cables
available on commercial terms are mass impregnated (MI) cables and extruded cross-linked
polyethylene (XLPE) cables.
The cost of subsea array and export cable supply and installation is about 14% of overall
capital costs of offshore wind farm projects [28]. Table 1 is a summary of the best information
found of cable manufacturers and their production capabilities [6], [17], [29], [30].
Table 1: Cable manufacturers and production capabilities (information taken from[6], [17], [29], [30])
Manufacturer Main Location
Array Cables[17], [30]
Export Cables[17], [29]
MVAC HVAC HVDC
3 Core XLPE XLPE MI
1 ABB Sweden
2 Exsym Japan
3 JDR UK
4 J-Power Japan
5 LS Cable South Korea
6 Nexans Norway
7 NKT Germany
8 NSW Germany
9 Parker Scanrope Norway
10 Prysmian Italy
11 Viscas Japan
Product available on commercial terms Lack of production capability
4
At present, JDR Cable Systems (JDR) is the only UK manufacturer of subsea array cables
for the offshore wind industry [17], [18], [31]. The UK has no capacity to manufacture cable
cores for subsea array cables. The cost of cable cores is about 40 per cent of the overall cable
cost and JDR currently imports these from the EU [18]. The UK does not have a high voltage
subsea cable manufacturing capability [18], [29], [32]. Only ABB and Prysmian have supplied
extruded HVDC cables to the offshore wind industry [17], [18].
1.4 Opportunities for UK Research and Innovation
The proposed North Sea Grid could offer opportunities for the UK to reduce cost of offshore
wind generation, install 66 kV array cables, develop DC wind farm collection systems, reduce
the frequency of AC power transmission and increase production capability of subsea cables.
1.4.1 Offshore Wind Cost Reduction
The UK Cost Reduction Monitoring Framework (CRMF) reported that the levelised cost of
energy from offshore wind reduced from £136/MWh to £121/MWh during the period 2010-
2014 [33]–[35]. The biggest contribution to the cost reduction was due to industry’s adoption
of larger turbines rated up to 6 MW. Larger turbines reduce the required number of turbines
per GW and decrease the number of array cable circuits. However, they require increased
spacing between turbines and so increase the length of array cables.
1.4.2 66 kV Array Cable
Increasing the voltage of array cables from 30 kV to 66 kV could reduce electrical losses,
increase wind turbine spacing distance, increase the power transfer capacity for a given
conductor size and result in fewer offshore AC substations. The 66 kV array cables would
preserve the number of wind turbines in each string of the collection system as the turbine
ratings increase. The two types of 66 kV array cables are dry-type and wet-type. Dry-type
designs are mature and available on commercial terms. The wet-type designs are a more
recent development which are more cost-effective than the dry-type designs. Therefore,
project developers may choose the wet-type designs in future [17].
1.4.3 Medium Voltage DC Wind Farm Collection Systems
Medium-voltage DC collection is a concept that is intended to connect wind turbines directly
to a medium voltage direct current (MVDC) system. High power MVDC converters with high
step-up conversion ratio are the key components in the MVDC collection systems and could
eliminate the requirement for offshore AC substations and platforms in the wind farm collection
system [18], [36], [37].
1.4.4 Low-frequency AC Transmission
Low-frequency AC transmission is a concept that decreases the frequency of AC systems,
reduces the cable charging current and extends the distance at which HVAC systems can be
cost-effective [29], [36]. This could increase the power transfer capacity of a given cable and
reduce the number of subsea export cables. At the onshore station, frequency converters
would be required to transform the low-frequency AC supply back to the frequency of the
onshore grid [29]. There is a need to further research, develop and demonstrate this concept
for submarine power transmission systems.
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1.4.5 Increase Manufacturing Capability of Subsea Cables
The Crown Estate Round 3 Grid Study reported that about 1200 km of HVAC export cable
and 5200km of HVDC export cables will be required to connect 25 GW of offshore wind
capacity [32]. At present, cable supply may constrain UK wind farm projects requiring high
voltage subsea cables [17]. The two possible routes to increase the UK manufacturing
capacity for subsea cables are [29], [31]: (i) Increase the voltage capability of existing lower
voltage cable manufacturing plants; and (ii) Attract an existing export cable supplier to set up
manufacturing facilities in the UK.
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2 TOPOLOGIES OF THE NORTH SEA GRID
This section describes the basic principles of submarine electricity transmission and the status
of HVDC transmission technologies for the proposed North Sea grid. It also outlines the
development of electricity interconnectors in the North Sea and the visions of the future North
Sea grid.
2.1 Submarine Electrical Power Systems
The electrical system of an offshore wind farm consists of a medium-voltage electrical
collection network and a high-voltage electrical transmission connection. Figure 2 shows the
simplified electrical system of an offshore wind farm in the North Sea. The collection grid uses
transformers in each wind turbine to step up the generation voltage of the wind turbines from
690 volts (V) to a medium voltage of 25 – 40 kV. A network of medium-voltage AC cables
connects the offshore wind turbines to an offshore AC substation. The transmission
connection uses the offshore AC substation to transform the medium voltage to a high voltage
of 130 – 150 kV for connection to an offshore converter station.
Remote offshore wind farms use offshore converter stations to transform the alternating
current generated from the offshore wind turbines into direct current. These offshore converter
stations are mounted on offshore converter platforms. HVDC submarine power cables connect
the offshore converter platforms to shore as shown in Figure 2. At the other end of the
submarine cables, the onshore converter stations receive the power from the wind farms and
convert it back to alternating current, which is fed into the terrestrial power grid.
2.2 Status of HVDC technology
The three key components of the HVDC networks of the proposed North Sea Grid are offshore
converter platforms, submarine power cables and onshore converter stations. The HVDC
submarine power cables can also interconnect the grids of two or more countries for energy
trading.
2.2.1 Offshore Converter Platforms
The two main components of an offshore converter platform are the topside and the foundation
support structure. Topsides house the offshore HVDC converter stations. Foundation support
structures host the topsides. Three possible foundation support structures are fixed, mobile
jack-up and gravity-base.
Offshore
Converter Platform
80 km
Electrical
Power Grid
Medium Voltage
Alternating Current
Offshore
AC Substation
North Sea
High Voltage
Alternating CurrentHigh Voltage
Direct Current (HVDC)
Onshore
Converter
Station
High Voltage
Alternating Current
Figure 2: Simplified electrical system of an offshore wind farm. Copyright GE Grid
7
The fixed platforms use jacket support structures which are attached into the seabed through
piles. The topsides and jackets are installed by lifting from a barge using a heavy-lift crane
vessel. The topside of a 1,000 MW HVDC converter platform could weigh up to 10,000 tons
and this will require a large crane vessel. This has implications for both costs and availability
and multiple offshore lifts [38].
A mobile jack-up platform has a self-installing topside which is mounted on a substructure.
These topsides house offshore converter platforms which have an embedded jack-up system.
The substructure is formed by steel piles which are installed around 50 metres deep into the
seabed. The floating topside is towed into position directly above the substructure and raised
up to about 20 metres above sea level by the embedded jack-up system. This approach has
no need for a large crane vessel. This concept was applied to the 864 MW Sylwin1 converter
platform with dimensions of 83 x 56 x 40 metres (length x width x height) and a total weight of
25,000 tons [39].
The gravity-base platform consists of a topside welded to a gravity base support (GBS)
structure. These GBS platforms are constructed onshore, towed into position and secured on
the seabed by their own weight and ballasting. This approach eliminates the need for heavy-
lift vessel or offshore jack-up operations. The 900 MW DolWin2 project under construction will
use the self-installing gravity-base structure platform for efficient production and ease of
installation [38].
2.2.2 Submarine Power Cables
According to the ENTSO-E [40] ten-year network development plan, about 20,000 km of
HVDC subsea power cables is required by 2030, of which 14,000 km (i.e. about 70%) are to
be installed in the North Sea. Cable manufacturers would need to expand their production
capabilities and more cable-laying vessels would be required to meet the predicted demand.
The two HVDC submarine power cable technologies available on commercial terms are mass-
impregnated (MI) paper cables and extruded cross-linked polyethylene (XLPE) plastic cables.
The central conductor of these cables is made either of copper or aluminium. The insulation
of MI paper cables consists of clean paper impregnated with a high viscosity compound based
on mineral oil. The next generation of MI paper cables would use paper polypropylene
laminate as insulation to achieve ratings of 650 kV and 1500 MW per cable. A single core MI
paper cable could have conductor size up to 2,500 mm2 and weigh about 37 kg per metre [41].
HVDC submarine cables have a sheathed and armoured layer for protection against harsh
conditions associated with offshore installation and service [41]. Table 2 is a summary of the
latest HVDC submarine power cables [3], [6].
Table 2: Status of HVDC Cables
Cable
Technology
Maximum Ratings Per Cable
Installed (until 2014) Under construction Achievable (up to 2020)
Capacity
(GW)
Voltage
(kV)
Capacity
(GW)
Voltage
(kV)
Capacity
(GW)
Voltage
(kV)
XLPE 0.25 200 0.5 320 1 500
MI 0.6 500 0.8 500 1.5
600-650
(PPLP
Technology)
XLPE- Extruded Cross Linked Polyethylene
MI – Mass Impregnated; PPLP – Paper Polypropylene Laminate
8
2.2.3 Onshore Converter Stations
There are two main HVDC converter technologies: line commutated converter (LCC), and self-
commutated voltage source converter (VSC). Table 3 is a summary of the status of HVDC
converters [6], [42].
Table 3: Status of HVDC Converters
Converter
Technology
Maximum Ratings Per Converter
Installed (until 2014) Under construction Achievable (up to 2020)
Capacity
(GW)
Voltage
(kV)
Capacity
(GW)
Voltage
(kV)
Capacity
(GW)
Voltage
(kV)
LCC 7.2 ± 800 8 ± 800 10 ±1100
VSC 0.5 ± 200 1 ± 320
2 ± 500 0.7 500*
*Converters have one pole
LCC-HVDC is a mature technology and suitable for long distance bulk power transfers. VSC-
HVDC is a more recent development and has independent control of active and reactive
power, improved black start capability, and occupies less space than LCC-HVDC. It is easier
to reverse power flows and hence form DC grids with VSCs than LCCs. A reversal of the
power flow direction in VSCs does not require a change in the polarity of the DC voltage.
Therefore, VSC-HVDC is the key technology for offshore wind power transmission and the
North Sea Grid. The MI paper cables are suitable for both LCC and VSC applications.
Extruded XLPE insulation cables are suitable for VSC applications and are available at
voltages up to 500 kV.
2.3 National Strategies
In 1991, the first offshore wind farm to became operational was the 4.95 Megawatt (MW)
Vindeby project, which was located at a grid connection distance of 2.5 km from the shore of
Denmark [43], [44]. By 2014, around 8,045 MW offshore wind capacity had been installed in
and connected to the electricity grids of 11 European countries. The per cent share of the
installed offshore wind capacity was 63.3% in the North Sea, 22.5% in the Atlantic Ocean and
14.2% in the Baltic Sea [45]–[47]. The installed offshore wind capacity in Europe is expected
to increase to 23.5 GW by 2020 [48].
At present, UK offshore transmission owners (OFTOs) use HVAC technology to connect about
5 GW of installed offshore wind capacity to the national grid [49]. It is expected that the
transmission circuits for the proposed Dogger Bank offshore wind farm to be located off the
east coast of GB, will use VSC-HVDC technology each rated at 1 GW and ±320 kV [50].
In Germany, offshore wind farms have been grouped into 13 clusters, and most of the offshore
VSC-HVDC platforms are each rated at up to 900 MW and ±320 kV [51]. In Belgium the total
power from offshore wind farms will be aggregated through two offshore HVAC platforms with
combined capacity of 2.3 GW. The two platforms will be interconnected together and
connected to an onshore substation using 220 kV AC submarine cables. The Belgian offshore
network design includes future interconnectors with France and the UK through an
international HVDC platform rated at up to 3 GW and above ±500 kV [52]. From Norway, new
HVDC interconnectors are planned to Germany rated at up to 1.4 GW and ±500 kV [53].
9
2.4 Development of Electricity Interconnectors in the North Sea
Interconnectors use submarine power cables to connect the electricity transmission systems
of adjacent countries. Interconnection could allow electricity to flow from one country to
another according to the market prices on either side of the interconnector. At present, four
countries (Great Britain, the Netherlands, Denmark and Norway) have 3.4 GW of
interconnection capacity through six HVDC interconnectors in the North Sea. Figure 2 shows
the existing and proposed HVDC interconnectors to be installed in the North Sea by 2020.
Table 3 is summary of the existing and proposed subsea interconnection capacities to be
installed in the North Sea by 2020.
Table 4: Subsea interconnection capacities in the North Sea by 2020
Country Project
Name
Completion
Date
Capacity
(MW)
Route
Length
(km)
Voltage
(kV)
Converter
Technology
1 DK-NO Skagerrak1&2 1977 500 127 ±250 LCC
2 DK-NO Skagerrak 3 1993 500 127 350 LCC
3 NL-NO NorNed 2009 700 580 ±450 LCC
4 GB-NL BritNed 2011 1000 250 ±450 LCC
5 DK-NO Skagerrak 4 2014 700 140 500 VSC
6 BE-GB NEMO 2018 1000 135 ±250 VSC
7 DE-NO Nord.Link 2018 1400 600 ±500 VSC
8 DK-NL COBRA 2019 700 350 ±320 VSC
9 GB-NO NSN 2020 1400 800 ±500 LCC
10 DK-GB Viking Link 2020 1400 700 - -
Total 9300 3809
BE-Belgium; DE-Germany; DK-Denmark; GB-Great Britain; NL-The Netherlands; NO-Norway
Interconnections:
1. Skagerrak 1&2
2. Skagerrak 3
3. NorNed
4. BritNed
5. Skagerrak 4
6. NEMO
7. Nord Link
8. COBRA
9. NSN
10. Viking Link
12
3
4
5
8
6
7
9
10
Norway
(NO)
Denmark
(DK)
Germany
(DE)
The Netherla
nds
(NL)
Belgium
(BE)
Great Britain
(GB)
HVDC Interconnectors
Existing
Proposed
North Sea
Figure 3: Existing and proposed HVDC interconnectors in the North Sea by 2020. Copyright d-maps.com
10
It is estimated that ten HVDC subsea interconnectors – having a total capacity of about 9.3
GW and a total route length of about 3800 km – will be installed in the North Sea by 2020.
Two of these interconnectors are to use the VSC technology. In December 2014, the new
VSC-based Skagerrak 4 project, which connects Denmark and Norway, was commissioned
to work in parallel with the existing LCC-based Skagerrak 3. This hybrid of a VSC and an LCC
scheme is the first to operate in such a configuration. The proposed COBRA interconnector
would use a single subsea cable to integrate offshore windfarms and interconnect the grids of
Denmark and the Netherlands by 2019. This will exemplify first steps in the development of a
multi-terminal HVDC system in the North Sea.
2.5 Visions of the future North Sea Grid
Existing HVDC subsea cables of the North Sea Grid are point-to-point circuits, and each circuit
provides a single service either for interconnecting transmission grids or connecting offshore
generators to onshore grids [54]. Although the topology of the future North Sea Grid has not
been agreed, the ENTSO-E [4] has proposed two possible topologies: (i) Local Coordination;
and (ii) Fully Integrated. The Local Coordination Topology assumes a continuation of existing
offshore grid development regimes. This will result in a multiplication of point-to-point circuits
in the North Sea. The Fully Integrated Topology is intended to interconnect several point-to-
point circuits and offshore wind power generation units. This will create a multi-terminal HVDC
system, in which any unused transmission capacity when wind farms are operating below their
peak generation can be used for balancing and energy trading between the grids of different
countries [55]. However, reliable operation of such multi-terminal HVDC schemes will most
likely require high power DC circuit breakers and direct current flow control devices, which are
still being developed. In Europe, manufacturers of DC circuit breakers have announced the
results of prototype tests in 2013 [56], [57]; in which direct current exceeding 3 kA was
interrupted in less than 3 milliseconds. In 2015, another prototype DC circuit breaker with rated
voltage of 200 kV and maximum breaking current of 15 kA and breaking time of 3ms was
tested in China [58]. The next step is to deploy a 363 kV DC circuit breakers with a fibre optic
current sensor into real HVDC networks in China [59].
11
3 OPERATION OF THE NORTH SEA GRID
In 1976, the first HVDC subsea cable in the North Sea, Skagerrak 1, was installed. This cable
was 127 km long, connected the grids of Denmark to Norway and had a rated capacity of 250
MW and 250 kV [60]. This was the beginning of submarine HVDC transmission across the
North Sea.
The two types of HVDC transmission technologies are Line Commutated Converters (LCC)
and Voltage Source Converters (VSC). LCC was used in the Skagerrak 1 project. VSCs are
a more recent development, which have independent control of real and reactive power,
improved black start capability and occupy less space than LCCs. It is easier to reverse power
flows and hence form DC grids with VSCs than LCCs. A reversal of the power flow direction
in VSCs does not require a change in the polarity of the DC voltage. Therefore VSC is now
the key technology for offshore wind power transmission and the proposed North Sea grid.
3.1 Physical Structure of VSCs
Figure 4 shows the schematic diagram of a VSC-HVDC transmission scheme. The main
components of the VSC scheme are the converter bridges, phase reactors, AC filters and
transformers.
3.1.1 Converter Bridges
The converter bridge of VSCs use Insulated Gate Bipolar Transistors (IGBTs) to transform
electricity from AC to DC at a transmitting end (rectifier) and from DC to AC at the receiving
end (inverter) [61]. The IGBT is a three-terminal power semiconductor device which is
controlled by a voltage applied to its gate. It allows power flow in the ON state and stops power
flow in the OFF state. Many IGBT cells are connected in series to form an IGBT valve, increase
the blocking voltage capability of the converter and increase the dc bus voltage level of the
HVDC system [61]–[63].
The DC capacitors in the converter bridge (shown in Figure 4) store energy, enable the control
of power flow, provide a low inductive path for the turned-off current and reduce DC voltage
ripple [62]–[65]. The DC side of the transmitting station and the receiving station can be
connected through DC cables, DC overhead lines or a combination of the two [61], [66]. Each
converter station has a cooling system, auxiliary system and control system [66].
3.1.2 Phase Reactors
Phase reactors are connected in series between the converter bridge and the transformers of
the VSC scheme as shown in Figure 4. They create a voltage difference between the output
voltage of the converter bridge and the AC system. The alternating current flowing through the
phase reactors controls active and reactive power of the VSCs [62], [63], [67]. Phase reactors
also reduce high frequency harmonic components of the alternating current.
Phase
ReactorTransformer
DC
Capacitor
Converter
Station A
AC
Filters
AC
System
Converter
Station BAC
System
DC Cable or
Overhaed Line
Figure 4: VSC-HVDC transmission scheme
12
3.1.3 AC Filters
Two-level VSCs can operate at a high frequency of about 1 kHz and above and create high
frequency harmonic components in their output voltage. AC filters are connected in parallel
between the phase reactors and the transformers to eliminate the high frequency harmonic
contents of the output voltage of the VSCs. Modular Multilevel Converters (see section 3.3)
do not need such a filter.
3.1.4 Transformers
Transformers interface the AC system to the AC filters, phase reactors and converter bridges
and regulate the voltage of the AC system to a value that is suitable for the HVDC system
[61], [63], [65].
3.2 Operating Characteristics of a VSC
VSC produce an output voltage waveform at their output and exchange active and reactive
power with the AC system. Figure 5 shows the schematic diagram and phasor diagram of two
AC voltage sources connected through a reactor. The voltage Vout at the sending end is
generated by a VSC and the voltage, Vac, at the receiving end is the voltage of the AC system.
Assuming that there are no power losses in the reactor shown in Figure 5a; and that the AC
system connected to the AC filter is ideal, then the active power (P) transferred through the
VSC, the reactive power (Q) at the sending end, and the apparent power (S) of the VSC are:
𝑃 = 𝑉𝑜𝑢𝑡 sin 𝛿
𝑋𝐿 𝑉𝑎𝑐
(1)
𝑄 = 𝑉𝑎𝑐 − 𝑉𝑜𝑢𝑡 cos𝛿
𝑋𝐿 𝑉𝑎𝑐
(2)
𝑆 = √𝑃2 + 𝑄2 (3)
where 𝛿 is the phase angle between the voltage phasor Vout and Vac (in Figure 5b) at the
fundamental frequency. Figure 6 shows the active power and reactive power capability curves
of a VSC during operation at ac voltages of 0.9 p.u, 1.0 p.u and 1.1 p.u. The three factors that
limit the operating range of the VSCs are the maximum active power transfer capability, the
maximum AC voltage of the power system and the maximum IGBT current capability.
VoutVac
Sending
End
Receiving
End
ΔV
ILXLIm
agin
ary
Part
Real Part
Vout
Vac
ΔV
I
(a) (b)
δ
0
Figure 5: Two AC voltage sources connected through an ideal reactor (a) Schematic diagram (b) Phasor diagram
13
3.3 VSC Topologies
The major VSC-HVDC manufacturers in Europe are ABB, Siemens and GE Grid. Other
potential world suppliers such as C-EPRI, RXPE, NanRui and XiDian are also able to deliver
VSC solutions [38], [68]–[71]. The three main types of Voltage Source Converters topologies
are two-level, three-level and multilevel. Figure 7 shows the output line-to-neutral voltage
waveforms from the three VSC topologies.
3.3.1 Two-level VSCs
Two-level VSCs use IGBTs valves (which consist of strings of series IGBTs) to switch between
the positive polarity and negative polarity of a charged DC capacitor as shown in Figure 7 [64],
[72]. Figure 8 shows the circuit for one phase of a two-level VSC with the DC capacitor
grounded at a midpoint. The two-level VSC has capability to generate output voltage with two
voltage levels 1
2𝑉𝑑𝑐 and −
1
2𝑉𝑑𝑐 between the midpoint of the DC capacitor and the point ‘a’
shown in Figure 8.
Figure 7: Output voltage waveforms from the two-level, three-level and multilevel topology of VSCs [72]
P [p.u]
Vac = 0.9 pu
Vac = 1.0 pu
Vac = 1.1 pu
Q [p.u]
Maximum AC Voltage Limit
Maximum IGBT Current Limit
Maximum Active Power Limit
Absorbing Vars
Supplying Vars
Figure 6: Power capability curve of a VSC. Limitation due to: (i) maximum active power capability (dotted); (ii) maximum AC voltage (dashed); and (iii) maximum IGBT current capability (solid)
14
The IGBT valves of the two-level converters are controlled using a Pulse Width Modulation
(PWM) technique. The PWM enables independent control of the magnitude and phase angle
of the AC voltage output of the VSC [73]. The line to neutral voltage waveform of a two-level
converter is shown in Figure 7. Two-level VSCs operate at a high switching frequency of 1
kHz and above and produce high frequency harmonic components. They have high switching
losses and require large AC filters at their output. They also require a special converter
transformer with capability to withstand high voltage stresses due to the large DC voltage
steps at the converter output. The total power losses of a two-level converter is about 1.6% of
its rated transmission capacity [74].
3.3.2 Three-level VSCs
The four different types of three-level voltage source converters are neutral point clamped, T-
type, active neutral point clamped and hybrid neutral point clamped [75]. Figure 9 shows the
circuit of one-phase of a neutral point clamped converter. Three-level VSCs have the capability
to generate an output voltage with three different voltage levels (1
2𝑉𝑑𝑐, 0 and −
1
2𝑉𝑑𝑐) per phase
between the point ‘a’ and a neutral point ‘0’ as shown in Figure 9. The switching signals of
their IGBT valves are generated using the PWM technique. They operate at a reduced
switching frequency, have lower switching losses, and their transformers are exposed to lesser
voltage stresses than the two-level converters.
AC Filter
Phase
ReactorInterface
Transformer
Idc
ILIac
VoutVac
ΔV
Vdc : DC Voltage with respect to ground
Vout : AC Voltage across IGBT Stack
ΔV : Voltage drop across phase reactor
Vac : Voltage across AC filter
Idc : Current through DC circuit
IL : Current through phase reactor
Iac : Current through AC filter
a : Interface point between phase
reactor and IGBT valves
List of symbols
IGBT
ValveVdc
12-
Vdc12
aVdc
Figure 8: One-phase of a two-level VSC
IGBT
Valve
Diode
Valve
+
+
Vdc
Vdc12
Vdc12
-
0a
Phase
Reactor
Figure 9: One-phase of a three-level neutral point clamped VSC
15
3.3.3 Multilevel Converters
Multilevel Converters are a more recent development which have a lower switching frequency,
reduced switching power losses, reduced harmonic components and occupy less space than
the two-level and three-level topology of VSCs. The two types of multilevel converters
available on commercial terms are the Modular Multilevel Converter (MMC) [69], [72], [76],
[77] and the Cascaded Two Level (CTL) [60], [73], [78] design.
Figure 10 shows the schematic diagram of a Modular Multilevel Converter (MMC). Each multi-
valve arm of the MMC consists of multiple submodules connected in series with an arm
reactor. A submodule is formed by a DC capacitor, IGBTs and diodes. It has capability to
produce a voltage step at its output. The submodules in each phase arm (shown in Figure
10(b)-(d)) are switched in the correct sequence to generate a sinusoidal AC voltage at the
converter output as shown in Figure 7 [63], [64], [67]. The IGBTs of the submodules are in
principle turned on once every cycle during steady state operation. MMCs have the capability
to control the phase angle, frequency and magnitude of their output AC voltage. They can also
control the real and reactive power flow from the converter stations [73], [74], [79].
The transformers of MMCs connected in a symmetrical monopole configuration are not
exposed to DC voltage stresses and can utilize a simple two-winding transformer (with
star/delta connection) [64]. The arm reactors of the MMCs filter the phase currents and limit
the inrush current during capacitor voltage balancing and circulating currents between the
phase arms during unbalanced operation [67].
GE Grid have also proposed a hybrid topology, known as the alternate arm converter (AAC),
which combines the features of the two-level converter and MMC topologies [80], [81]. The
AAC has reduced number of submodule circuits and lower semi-conductor losses than the
MMC and has improved functional capabilities than the two-level converters [63], [67], [80].
Each converter arm of the AAC operates for 180 degrees. A director switch is utilised to
increase the voltage blocking capability of each arm and facilitate zero voltage switching
during direct current commutation from the upper arm to the lower arm [67], [80], [81].
SM1,a
SM2,a
SMN,a
SMN+1,a
SMN+2,a
SM2N,a
SM1,b
SM2,b
SMN,b
SM2,c
SMN,c
SMN+1,b
SMN+2,b
SM2N,b
SMN+2,c
SM2N,c
Vb
Vc
Va
icibia
+
-
+
-
+
-
Phase arm Multi-valve arm Submodule (SM)
Idc
Vdc
Half-Bridge
VSM
+
-
S1
S2
vc+
-(b)
Full -Bridge
VSM
+
-
S1
S2
vc+
-(c)
S3
S4
Clamp Double
VSM
+
-
S1
S2
vc
(d)
S3
S4
S5
+
-
Types of
Submodule
Circuits
vc
Upper-arm
Voltage
Lower-arm
Voltage
Arm
reactors
SMLevel,phase
(a) Three-phase Topology
SMLevel+1,phase
Figure 10: Schematic diagram of an MMC-HVDC Scheme (a) Three-phase Topology (b) Half-bridge submodule (c) Full-
bridge submodule (d) Clamp double submodule
16
3.3.4 Submodule Circuits
The three main types of switching circuits in the submodules of the MMCs are half-bridge, full-
bridge and clamp double. The half-bridge circuit is the simplest design and consists of two
IGBTS with anti-parallel diodes and a DC capacitor as shown in Figure 10b. The output voltage
of the half-bridge circuit is either 0 or the DC capacitor voltage (Vc) [82] and current flows
through only one IGBT during steady state operation. The half-bridge circuit has the lowest
cost and the least conduction losses [63], [64].
The full-bridge circuit has four IGBTs with anti-parallel diodes and a DC capacitor as shown
in Figure 10c [64], [79], [82]. The voltage output of the full bridge circuit is +Vc, 0 or -Vc and the
current flows through two IGBTs during steady state operation. MMCs with full-bridge circuits
have the advantage of blocking DC faults. They have higher capital costs and increased
conduction losses than the half-bridge circuits [83].
The clamp double circuit consists of two half-bridge designs connected in series. The positive
terminal of one half-bridge is connected to the negative terminal of the other as shown in
Figure 10d [67], [82], [83]. It has five IGBTs with anti-parallel diodes, two DC capacitors and
two additional diodes. The voltage output of the clamp double circuit is 0, Vc or 2Vc and the
current flows through three IGBTs during steady state operation [79], [82], [83]. The switch S5
is always in the ON state during normal operation and contributes only to conduction losses.
The clamp double circuit has improved efficiency over the full-bridge circuit and has higher
conduction losses than the half bridge circuit [79], [83].
3.3.5 Examples of VSC-HVDC Projects
Table 5 outlines some examples of existing and proposed VSC-HVDC submarine power
transmission schemes (information taken from [67], [72], [73], [84], [85]).
Table 5: Examples of existing and proposed VSC-HVDC schemes (information taken from [67], [72], [73], [84],
[85])
Project Name
(Country)
Converter
Topology
Ratings per converter
Application Date Capacity
(MW)
Voltage
(kV)
Estlink
(Estonia-Finland) Two-level 350 ±150
Electricity interconnection and grid reinforcement
2006
Borwin 1 (Germany)
Two-level 400 ±150 Connection of offshore wind farms
2009
Cross Sound
(USA) Three-level 330 ±150
Electricity interconnection
and grid reinforcement 2002
Murray Link (Australia)
Three-level 220 ±150 Electricity interconnection and grid reinforcement
2002
Trans Bay (USA)
Modular Multilevel
400 ±200 Electricity interconnection and grid reinforcement
2010
Borwin 2 (Germany)
Modular Multilevel
800 ±300 Connection of offshore wind farms
2013
Dolwin 1
(Germany)
Cascaded
Two-Level 800 ±320
Connection of offshore wind
farms 2015
Dolwin 3 (Germany)
- 900 ±320 Connection of offshore wind farms
2017
17
3.4 HVDC Configuration and Operating Modes
The five main configurations of a two-terminal HVDC scheme are back-to-back, asymmetrical
monopole, symmetrical monopole, bipolar and diode rectifier with VSC inverter. Table 6 is a
summary of the different configurations and operating modes of a two-terminal HVDC system.
3.4.1 Back-to-Back HVDC Scheme
Back-to-back systems have no transmission lines or high-voltage insulated cables and both
converters are located at the same site as shown in Figure 11 [66], [86]. They are used for
interconnection of AC systems operating at the same or different frequencies. Their power
transfer capability is limited by the relative capacities of the adjacent AC systems at the point
of connection [86]. The converter control system, cooling system and auxiliary systems can
be integrated into configurations common to the two converter ends.
3.4.2 Asymmetrical Monopole
Asymmetrical monopole systems are the simplest and least expensive systems for HVDC
transmission between two converter stations [63], [66], [76], [86]. They have a high-voltage
conductor (a cable or an overhead line) and a return path. The return conductor could be either
a low voltage metallic conductor (metallic return) or an earth or sea conductor (ground return)
as shown in Figure 12. At heavily congested areas, fresh water crossings and areas with high
soil resistivity, metallic return is more practical than ground return [66], [86].
3.4.3 Symmetrical Monopole
Symmetrical monopole systems have two high-voltage conductors connected in parallel
between the positive polarity and the negative polarity of the two converter ends as shown in
Figure 13. The centre point of the converters is connected to the ground through a high
impedance to provide a reference for the DC voltage. They are more suitable for VSC-based
HVDC transmission schemes. The drawback of monopolar HVDC systems (with a
symmetrical and asymmetrical configuration) is that their total power transfer capacity is lost
during a cable fault or a converter outage.
3.4.4 Bipolar HVDC Scheme
The bipolar configuration combines two monopolar schemes to form two DC circuits with two
high-voltage conductors and a common return path as shown in Figure 14 [63], [66]. They
have reduced costs and lower transmission loses than two separate monopole schemes [76].
Each DC circuit has the ability to operate at up to half of the rated HVDC transmission capacity.
The two DC circuits are arranged so that the neutral return current of the two poles partly or
completely cancel each other out [66], [86].
During a system disturbance, the bipolar system can either operate in a monopolar ground
return mode or the monopolar metallic return mode. Monopolar ground return operation is
suitable for converter outages or high-voltage conductor outages [66], [76].
Monopolar metallic return operation is possible, during converter outages only, by using the
conductor of the faulty pole as a metallic return path. This requires a converter by-pass switch
at each end of the faulty pole and a metallic-return transfer breaker (MRTB) as shown in Figure
15. The MRTB commutates the return current from the low resistance of the earth into that of
the high voltage conductor of the faulty pole [66], [86]. Monopolar metallic return operation is
the most suitable system for overhead HVDC transmission.
18
3.4.5 Diode-Rectifier and VSC-Inverter Concept
An offshore diode-based rectifier connected to an onshore VSC-based inverter is a concept
that is intended to facilitate the connection of large offshore wind farms [87]–[89]. This concept
was proposed and developed by researchers at the Polytechnic University of Valencia, Spain
in collaboration with industrial partners at Siemens, Germany [88], [90]. The offshore diode-
rectifier platform will have reduced costs, reduced power losses and occupy less space than
existing offshore VSC platforms [89].
Multiple diodes cells are connected in series to increase the voltage withstand capability of a
diode valve. The diode valves are arranged into a bridge to form an uncontrolled rectifier. The
HVDC transmission scheme shown in Figure 16 consists of an offshore 12-pulse diode-
rectifier and an onshore VSC. A recent press release indicated that this new offshore
converters are likely to be available by 2016 [89].
19
Table 6: Configuration and Operating Modes of HVDC Systems
HVDC Scheme Configuration Number of Converters Number of Cables
Availability
Rectif ier Inverter HVDC LVDC
1. Back-to-Back
Figure 11: Back-to-back HVDC scheme with mid-point ground
1 1 0 0 Zero output during pole outages.
2.
Asymmetrical
Monopole
HVDC Cable
Metallic return
Figure 12: Asymmetric monopolar HVDC scheme with ground return or metallic return
1 1 1 1 Zero output during cable
or pole outages.
3.
Symmetrical Monopole
HVDC Cable (+ve)
HVDC Cable (-ve)
Figure 13: Symmetric monopolar HVDC scheme with mid-point ground
1 1 2 0 Zero output during cable or pole outages.
4. Bipole
HVDC Cable
HVDC Cable
Figure 14: Bipole HVDC scheme with mid-point ground
2 2 2 0
Half capacity during pole
outages. Zero output during cable outages.
HVDC Cable
HVDC Cable
Metallic-return
transfer breaker
Figure 15: Bipole HVDC scheme with metallic return for pole outage
2 2 2 1 Half capacity during cable or pole outages.
5. Diode-Rectif ier w ith VSC Inverter
HVDC Cable
HVDC Cable
Diode rectifier
Figure 16: HVDC scheme with uncontrolled diode-rectifier and VSC inverter
1 2 2 0 Zero output during cable or pole outages.
20
3.5 Multi-Terminal HVDC Systems
Multi-terminal HVDC schemes are intended to facilitate the transfer of electricity generated
from offshore wind farms to land, supply electricity to offshore oil and gas installations and
interconnect the grids of adjacent countries. VSC has improved active and reactive power
control capabilities than LCC and its polarity does not change when the direction of power flow
changes. Multiple VSCs can be connected to a DC bus with fixed polarity to form a multi-
terminal HVDC (MTDC) system [91]–[93].
3.5.1 Control of MTDC Grids
The operation of MTDC grids requires at least one converter to regulate the DC voltage [93].
Onshore converters will connect the main AC systems, pumped hydro storage units or other
energy storage plants to MTDC grids, maintain the DC voltage and balance power flows in the
MTDC systems [91]. The four main concepts to achieve the desired DC load flow in the
onshore converters are [94]: (i) DC voltage versus active power droop together with dead
band; (ii) DC voltage versus DC current droop with dead band; (iii) DC voltage versus active
power droop; and (iv) DC voltage versus DC current droop.
Converter stations connected to offshore generation sources or loads regulate the frequency
of the offshore AC networks by varying the power transferred through the converters [91], [94].
They absorb the AC generation from offshore wind turbines into the MTDC system or transfer
power from the MTDC system to AC loads in offshore oil and gas platforms [91], [92].
Information and Communication Technologies (ICT) and Supervisory Control and Data
Acquisition (SCADA) systems are likely to be required to maintain secure and optimal
operation of the MTDC grids or restore the grid in a fast and secure way after a power failure
[91]. The HVDC Grid Study Group proposed a HVDC Grid Controller. This concept is intended
to monitor the status of individual converter stations, optimize the power flow within the DC
network and transmit control characteristics and operating set points to individual converter
station controllers [91], [94], [95]. Figure 17 shows the signal flow between the proposed
HVDC Grid Controller and three VSC stations.
3.5.2 Direct Current Flow Control Devices
A meshed HVDC grid will have parallel circuits (i.e. cable or overhead line) between its
converter terminals. The power on the DC side of each converter terminal can be fully
controlled. The DC current flowing in each circuit may not be controllable, since it depends on
the resistance of the circuit and the DC voltage difference between the converters at both ends
of the circuit [96]. The direct current will flow from one converter terminal to another through
the path of least resistance and may overload the circuit with the least resistance.
HVDC Grid Controller
Set
-poi
nts
Sig
nal
s
Set
-poi
nts
Sig
nal
s
Set
-poi
nts
Sig
nal
s
VSC1
VSC2
VSC3
Figure 17: Signal flow between the HVDC Grid Controller and three voltage source converter stations.
21
The two methods for controlling the current flow around a meshed DC circuit are the switched
resistance method or the voltage insertion method [97]. Figure 18 shows the two methods for
controlling the current flow around a meshed DC circuit.
Multiple resistors (R1 to RN) are connected in series with a DC circuit and each resistor is
controlled using a parallel electronic switch or mechanical switch (S1 to SN) to change the
resistance of the conduction path as shown in Figure 18a. This solution has low cost, high
power losses and lacks the capability to reverse the direction of current flow in the DC cable
or line. In the voltage insertion method, a DC voltage of appropriate magnitude and polarity is
inserted in series with a direct current branch. Electronic switches control the polarity of the
voltage source and regulate the current magnitude and direction of current flow in the DC
circuit as shown in Figure 18b.
3.5.3 DC Circuit Breakers
The three types of DC circuit breakers are mechanical, solid state and hybrid [98]. Figure 19
shows the structure of the different types of DC circuit breakers.
Resonant DC circuit breakers combine mechanical AC circuit breakers in parallel with a surge
arrester and a commutation circuit, consisting of an LC resonant circuit as shown in Figure
19a [99], [100]. They have low cost and low conduction losses and their switching time is
within 30 – 50 milliseconds.
Solid state DC circuit breakers consist of a stack of semiconductor switches (IGBTs)
connected in parallel with a voltage limiting device (e.g. a string of varistors), as shown in
Figure 19b. The stack of switches is formed by series and anti-series IGBTs to avoid an
uncontrolled conduction of current through the diodes [101].
VSC1
VSC2
VSC3
R1 RN
S1 SN
DC Cable
or Line 1
DC Cable
or Line 2
DC Cable
or Line 3
VSC1
VSC2
VSC3
DC Cable
or Line 1
DC Cable
or Line 2
DC Cable
or Line 3
Voltage
Source
(a) (b)
Figure 18: Direct Current Control using (a) Switched Resistors and (b) Voltage Insertion.
Commutation CircuitMetal
Contacts
Varistor
Varistor
Stack of IGBT
(b)(a)
(c)
Load commutation switch
Mechanical Switch
Main DC Circuit Breaker
Residual DC
circuit breakerL
Series Inductor
Figure 19: Structure of different types of DC circuit breakers (a) Resonant (b) Solid state (c) Hybrid
22
Solid state DC circuit breakers have the ability to quickly interrupt DC fault currents without
arcing and their switching time is in the order of a few microseconds. They are more expensive
and have higher conduction losses than resonant DC circuit breakers.
Hybrid DC circuit breakers combine the structure and functional capabilities of semiconductor
switches and mechanical DC circuit breakers, as shown in Figure 19c, to achieve reduced
conduction losses compared with semiconductor switches and have faster switching times
than mechanical switches [99], [100]. During the breaking operation, the load commutation
switch is turned off and the direct current is transferred to the main circuit breaker branch.
Then the mechanical switch opens and isolates the load commutation switch from the network
voltage and the main circuit breaker is turned off. The varistors decrease the resulting
inductive currents to zero and the residual DC circuit breaker shown in Figure 19c is opened
[101].
Voltage source converters with full bridge or clamp double submodule circuits have capability
to block DC fault currents. However, they have higher number of components and increased
power losses than VSCs with half-bridge submodule circuits as shown in Figure 10 [63], [64],
[99].
At present, original equipment manufacturers (ABB, GE Grid and C-EPRI) have developed
prototypes of hybrid HVDC circuit breakers operating at DC voltages up to 200 kV with a
maximum current breaking capacity of 15 kA and a breaking time of 3 ms [56]–[58]. The next
step is to install a DC circuit breaker with a rated DC voltage of 363 kV into real HVDC
networks at a substation in Fuping, Shanxi province, China, and coordinate their operation in
a multi-terminal HVDC system [59]
3.5.4 The Supernode Concept
The Supernode is a concept that is intended to facilitate bulk power transfer of offshore wind
power through multiple VSCs and eliminate the requirement for DC circuit breakers in HVDC
transmission. Figure 20 shows a Supernode for offshore wind power transmission. It consists
of an islanded AC network with multiple AC/DC converters. The converters of the Supernode
would be required to have fault ride through capabilities and regulate the frequency and AC
voltage of the AC island [3]. Additional offshore converter platforms would be required to
connect new HVDC circuits to the Supernode and this could result in high grid expansion costs
and increased power losses.
2×500 MW2×500 MW
2×500 MW2×500 MW
1 GW
1 GW
1 GW
1 GW
± 320 kV
± 320 kV
± 320 kV
± 320 kV
=
=
=
= 400 kVAC Hub
=Converter Station
HVAC
HVDC
Figure 20: A Supernode for offshore wind power transmission
23
3.5.5 DC-DC Converters
DC-DC converters would connect DC systems operating at different DC voltage levels, enable
the integration of offshore wind farms through MVDC collection systems and facilitate multi
terminal HVDC transmission [37], [102]–[105]. They could be utilised to transfer power
between VSC-based and LCC-HVDC systems [105]. Also, some DC/DC converter topologies
have capability to block DC fault currents [99], [105]. The proposed North Sea Grid could be
built using a combination of DC-DC converters and Supernodes.
3.5.6 Wide Band Gap Devices
At present all semiconductor devices use Silicon (Si), which has low voltage blocking
capabilities and low current ratings. Wide band gap materials, such as Silicon Carbide (Sic),
Gallium Nitride (GaN) and diamond, have higher breakdown field strength than Silicon (Si:
0.3; SiC: 1.2-2.4; GaN: 3.3; and diamond: 5.6 MV/cm), but are not available on commercial
terms. Future HVDC systems with wide band gap devices would have thinner chips, reduced
number of components and decreased conduction losses than existing Si-based technologies.
There is a need to further research and develop wide band gap devices for HVDC systems
[100].
3.5.7 Requirements for Standardization and Interoperability
A new multi terminal HVDC system will consist of multiple converters, control systems and
protection devices supplied by different manufacturers. Each manufacturer’s technology differ
and cannot be easily combined with that of others [91], [94], [106]. Standardization will
facilitate the interoperability of equipment supplied by different manufacturers and develop an
efficient and competitive supply chain for MTDC network equipment [91], [107]. Error!
Reference source not found. is a summary of the technical activities related to
standardisation of multi-terminal HVDC Grids (information taken from [91], [94], [101], [107],
[108])
Table 7:Summary of activities related to standardisation of HVDC Grids
Technical Committee (TC) or Working Group (WG)
Description (Start date – End date)
Status
CIGRE B4-52 HVDC Grids Feasibility Study (2009 – 2012)
Report published in [108]
CIGRE B4-56 Guidelines for Preparation of Connection Agreements or Grid Codes for HVDC Grids
(2011 – 2014)
To be published
CIGRE B4-57 Guide for the Development of Models for HVDC Converters in a HVDC Grid
(2011 – 2014)
Report published in [101]
CIGRE B4-58 Devices for Load Flow Control and Methodologies for Direct Voltage Control in a Meshed HVDC Grid
(2011 – 2014)
To be published
CIGRE B4/B5-59 Control and Protection of HVDC Grids (2011 – 2014)
To be published
CIGRE B4-60 Designing HVDC Grids for Optimal Reliability and Availability Performance
(2011 – 2014)
To be published
CIGRE B4/C1.65 Recommended voltage for HVDC Grids (2013 – 2015)
Work in progress
CENELEC TC8X European Study Group on Technical Guidelines for DC Grids
(2010 – 2012)
Findings published in [94], [107]
New CENELEC TC8X WG06
A continuation of the 2010-2012 Working Group
(2013 – Work in progress
IEC TC-57 WG13 CIM Power Systems Management and Associated Information Exchange
(2014 –
Reports available at [109]
24
Standards are required to harmonise the basic principles of design and operation of MTDC
systems and guide investors on how to specify equipment for a multi-vendor HVDC grid [91],
[107], [110]. They shall consider that new technologies may be developed in future and not
create barriers to innovation [91].
The standardization of equipment functions, DC voltage levels, DC grid topologies, control
and protection principles, fault behaviour and communication (protocols) will be important for
grid expansion and planning [91], [107]. Functional specifications for interoperability of
equipment will be required for AC/DC converters, submarine cables, DC overhead lines, DC
choppers, charging resistors, DC circuit breakers and communication for network control and
protection [91], [94], [95].
Organisation such as International Council on Large Electric Systems (CIGRE), European
Committee for Electrotechnical Standardisation (CENELEC), International Electrotechnical
Commission (IEC) are preparing technical guidelines standards for multi-terminal HVDC
systems. Also, the European Network of Transmission System Operators for Electricity
(ENTSO-E) has published a draft network code on HVDC connections [106].
3.6 Modelling and Testing of MTDC Grids
A present, all the HVDC connections in the UK are independent circuits which transfer power
from one AC system to another and each solution is supplied by a single manufacturer. There
is a lack of experience in the operation and control of multi-vendor, multi-terminal HVDC
systems [111], [112].
Scottish Hydro Electric Transmission in collaboration with other Transmission Owners (i.e.
National Grid and Scottish Power), will build a Multi-Terminal Test Environment (MTTE) for
HVDC systems by 2017 [112]. This facility will combine real time simulators with physical
HVDC control panels to test the compatibility of the control and protection systems provided
by different manufacturers [113].
In Europe, 39 partners from 11 countries are working on the BEST PATHS project to develop
five demos consisting of full scale experiments and pilot projects to remove existing barriers
to multi-terminal HVDC grids by 2018 [114]. The experimental results will be integrated into
the European impact analyses and form the basis for development of the proposed North Sea
grid [115].
3.7 Potential Interactions between HVAC and HVDC systems
In the UK, electricity is mainly generated and transmitted using alternating current (AC) [23].
Direct current (DC) is not so widely used and to date has been applied in a small number of
submarine electricity interconnections [116], [117]. It is anticipated that by 2020, more HVDC
systems would be connected to the UK electricity transmission system to form a mixed AC-
DC system [6], [26]. The potential interactions between the HVAC and HVDC systems would
affect the planning, operation and control of electricity networks.
Multi-terminal VSC-HVDC systems are intended to transfer the power generated from offshore
wind farms to land and interconnect the grids of adjacent countries in order to replace
synchronous machines of power systems. This change in generation mix will result in a
reduction of system strength. The strength of a power system is a measure of its ability to
maintain stable operation during a grid disturbances such as switching events, faults on
transmission lines, loss of generation or load. The two indicators of power system strength are
system inertia and short-circuit level [6], [118].
25
VSC-HVDC schemes are required to support AC grids with low inertia or low short-circuit level.
The capability of the VSCs to support weak AC systems depends on the configuration of the
mixed AC-DC system and the control mode and operating characteristics of the VSC. Further
discussions on the potential interactions between mixed AC-DC systems are included in the Appendix B.
26
4 OVERVIEW OF SUPPORT FOR THE DEVELOPMENT OF THE NORTH SEA GRID
The North Sea Grid is a concept that is intended to transfer power from offshore wind farms
in the North Sea to land and interconnect the grids of adjacent countries. The UK funding
landscape for the proposal to develop offshore wind power from the North Sea varies across
nine (9) technology readiness levels (TRLs). Discussions on the different TRLs and the
organisations who fund them are included in Appendix C [119], [120]. The three categories of
the funding organisations are regions, national and European.
4.1 Regions
The Devolved Administrations of Northern Ireland, Scotland and Wales fund innovation in the
offshore wind industry across the different technology readiness levels (TRLs) through
different support schemes. These support schemes were published by the Department of
Business, Innovation and Skills (BIS) in [121], and will help to develop a capability to address
market failures in the regions [122].
4.1.1 Northern Ireland
The support schemes for the development of the offshore wind industry in Northern Ireland
are [121]:
Collaborative Networks Programme – is an industry-led project intended to address
key challenges in the offshore wind sector. The existing collaborative networks are
Global Wind Alliance, Global Maritime Alliance, Total Marine Support Services, Energy
Skills and Training Network and Energy Storage Network.
Invest Northern Ireland (Invest NI) – provide financial and non-financial incentives to
manufacturing companies to maximise efficiencies, research and develop new
products and export finished products. They provide an innovation voucher with a
value of £4,000 to be used to solve an innovation challenge for small businesses.
The Centre for Advance Sustainable Energy (CASE) – is a £10 million research centre
with focus on the development of turbines, integration and storage, energy efficiency
and energy from biomass.
4.1.2 Scotland
The support schemes for the development of the offshore wind industry in Scotland are:
Scottish Enterprise and Highlands and Islands Enterprise – is investing £40 million
through the Prototyping for Offshore Wind Energy Renewables Scotland (POWERS)
project to promote the deployment and testing of offshore wind turbines. The fund will
remain open until 2017 [123].
National Renewables Infrastructure Fund (N-RIF) – has a £70 million budget to support
the development of a National Renewables Infrastructure Plan (N-RIP) for the offshore
wind industry in Scotland. The fund will help to develop key infrastructures to support
manufacturing, deployment and operations and maintenance of offshore renewable
energy devices at 11 sites identified by the Scottish Enterprise in the N-RIP [123],
[124].
Scottish Innovative Foundation Technologies Fund (SIFT) – will provide £15 million for
the design, development, manufacture and deployment of innovative offshore wind
foundations in Scotland between June 2014 and July 2019 [123].
27
Scottish Energy Laboratory (SEL) – is a network of energy research, development and
demonstration facilities in Scotland. It is formed by the European Marin Energy Centre
in Orkney, the Hydrogen Office in Fife and the European Offshore Wind Deployment
Centre in Aberdeen [121].
Renewable Energy Investment Fund (REIF) – will provide £103 million for the
development of marine renewable energy, community owned renewable energy,
renewable district hearing and innovative renewable technologies (including offshore
wind). It is available in the form of loans, equity investments and loan guarantees.
4.1.3 Wales
The support schemes for the development of the offshore wind industry in Wales are [121]:
SMART Cymru Research, Development and Innovation Funding – provides financial
assistance to Welsh-based businesses for the research and development of new and
innovative technologies.
Low Carbon Energy and Marine Power Institute – will offer initial, refresher,
progression and transitional training for the development of skills in power generation
and distribution technologies energy networks.
The Department for Economy, Science and Transport provide practical help and
guidance to companies in Wales in order to enhance the existing manufacturing
capabilities, improve profits and attract new investments.
4.2 National
The UK departments and organisations that support the development of offshore wind and
offshore grids are the Research Councils, Technology Strategy Board, Office for gas and
electricity markets (Ofgem), Energy Technologies Institute, Carbon Trust and the Department
of Energy and Climate Change (DECC). These organisations work together as the Low
Carbon Innovation Coordination Group.
4.2.1 Research Councils
The Research Councils support basic research into new technologies in the UK through an
Energy Programme designed to deliver energy-related research and post graduate training
with an annual budget of about £100 million. This includes support for the UK Energy
Research Council (UKERC). At present, the Engineering and Physical Science Research
Council (EPSRC) is investing about £42 million in 21 research projects, with grants above
£100,000 each, related to the proposed North Sea grid. Appendix D is a summary of the
EPSRC-funded research projects related to the proposed North Sea grid.
In 2013 and 2014, the EPSRC announced four new Doctoral Training Centres to ensure a
continued supply of scientists and engineers between 2014 and 2023 with skills focused on
the deployment of offshore wind technologies and their integration into power networks [121].
These are:
EPSRC Centre for Doctoral Training in Wind and Marine Energy Systems at the
University of Strathclyde and the University of Edinburgh with a grant of £3.89 million
[125], [126].
EPSRC Centre for Doctoral Training in Renewable Energy Marine Structures at the
Cranfield University and University of Oxford with a grant of £3.98 million [127], [128].
EPSRC Centre for Doctoral Training in Future Power Networks and Smart Grids at the
University of Strathclyde and Imperial College London with a grant of £4.40 million
[129], [130].
28
EPSRC Centre for Doctoral Training in Power Networks at the University of Manchester
with a grant of £3.95 million [131], [132].
4.2.2 Technology Strategy Board
The Technology Strategy Board helps UK companies to develop new technologies and
products in a number of sectors including energy and provides funding to an offshore
renewable energy catapult centre. The Technology Strategy Board is now called Innovate UK.
The Technology Strategy Board will [121]:
Collaborate with the EPSRC and DECC to provide up to £25 million through an Energy
Catalyst scheme intended to support projects in the areas of technical feasibility,
technical development and pre-commercial technology validation. The first round of
applications will close in November 2015.
Collaborate with the EPSRC to invest about £7 million in the Infrastructure for Offshore
Renewables Competition organized in December 2014 for demonstration projects that
reduce the cost of energy for offshore renewables industry. The three areas of focus
are electrical infrastructure, support structures, and sensors and monitoring.
Provide up to £5 million per year from 2013 to 2015 through an Energy Programme to
develop a UK offshore wind industry through technology transfer from parallel industries
such as the offshore oil and gas sector.
The Appendix E is summary of the ongoing demonstration projects (with grants above
£100,000 each) supported by the Technology Strategy Board.
4.2.3 Energy Technologies Institute
Energy Technologies Institute is a partnership between the UK Government and global
engineering companies – BP, Caterpillar, EDF, E.ON, Rolls-Royce and Shell [133]. The ETI
will invest about £60 million to develop the offshore wind industry with focus on floating
platforms for turbines, new turbine blade manufacturing technologies and demonstration
facilities for testing the reliability of large turbines [121].
In 2011, the Energy Technologies Institute (ETI) and the EPSRC funded an Industrial
Doctorate Centre in Offshore Renewable Energy (IDCORE) to train at least 10 PhD level wind
energy researchers per year over a five year intake period of the centre [121]. The centre is a
partnership between the University of Edinburgh, University of Strathclyde, University of
Exeter, the Scottish Association for Marine Science and HR-Wallingford [134]. The research
centre focuses on offshore wind farm optimisation, offshore operations and maintenance and
next generation turbine foundations [121].
4.2.4 Office of Gas and Electricity Markets (Ofgem)
The Office of Gas and Electricity Markets (Ofgem) provides up to £81 million per year to fund
an Electricity Network Innovation Competition (NIC). The Electricity NIC will enable electricity
network operators to develop and demonstrate new technologies with operating and
commercial arrangements in order to provide environmental benefits, cost reductions and
security of supply [135].
29
At present, there are five Electricity NIC projects - two were awarded in 2013 and three were
awarded in 2014. Table 8 is a summary of the five Electricity NIC projects. The Enhanced
Frequency Control Capability project awarded in 2014 is now called SMART Frequency
Control Project. The project will investigate how newer technologies – such as wind farms,
solar photovoltaics, energy storage and demand-side response – can help to maintain system
frequency [136].
Table 8: Electricity Network Innovation Competition Projects (information taken from [136]–[138])
Project Company Name Concept Amount
Awarded
(£ million)
Start
Year
Duration
(years)
Multi Terminal Test
Environment
(MTTE) for HVDC
systems
Scottish Hydro
Electric
Transmission
A collaborative centre to simulate
the impact of HVDC technology
on electricity network operation
and control [137].
11.3 2013 7
Visor Scottish Power
Transmission
New techniques for operating and
planning the power system using
wide area monitoring systems
[137].
6.5 2013 4
Enhanced
Frequency Control
Capability
National Grid
Electricity
Transmission
To develop new techniques to
enhance National Grid’s capability
to control system frequency [138].
6.9 2014 3
Offshore Cable
Repair Vessel and
Universal Joint
TC Ormonde
OFTO Ltd.
To convert an existing telecom
cable repair vessel into a power
cable repair vessel and
demonstrate a new universal
cable jointing system [138].
9 2014 3.5
Modular Approach
to Substation
Construction
Scottish Hydro
Electric
Transmission
To develop and trial modular
techniques in electrical substation
construction through innovation in
design and civil engineering [138].
2.8 2014 4.5
4.2.5 Carbon Trust
In 2008, Carbon Trust in collaboration with 9 offshore wind developers set up an Offshore
Wind Accelerator (OWA) project in order to reduce the cost of offshore wind by 10 per cent.
The industrial partners provide two-thirds of the fund for the OWA and Department of Energy
and Climate Change and the Scottish Government provide the counterpart funds. The five
research areas of the OWA are electrical systems, cable installations, foundations, access
and wakes and wind resources [139]. It is expected that the OWA project will extend until 2022
and new developers will have the opportunity to join the consortium by the end of 2016 [140].
4.2.6 The Department of Energy and Climate Change (DECC)
In 2011, DECC allocated up to £30 million to support offshore wind innovation projects through
its partnership with the Carbon Trust, Energy Technologies Institute, Research Councils UK,
and Technology Strategy Board. Also, DECC collaborates with Eurogia+ and the Technology
Strategy Board to encourage UK companies to participate in transnational and innovative
industrial research, development and demonstration projects for low carbon technologies
[121].
4.3 European
The European Union (EU) provides funding for research, development and demonstration of
offshore wind technologies and offshore electricity transmission grids.
30
The EU’s support was provided through the 7th Framework Programme (FP7) and the
Intelligent Energy Europe (IEE) Programme from 2007 to 2013. In 2014, the two funding
programmes were replaced with a Horizon 2020 programme [121].
4.3.1 7th Framework Programme (FP7)
The 7th Framework Programme is a funding instrument under the EU’s Strategic Energy
Technologies (SET) Plan. The major FP7 project related to the research, development and
demonstration of offshore grids are:
BEST PATHS – is a research and demonstration project carried out by 39 partners
from 11 countries in Europe and intend to develop five demos consisting of full scale
experiments and pilot projects to facilitate the development of multi-terminal HVDC
grids [114]. The demos will focus on: integration of offshore wind farms through
submarine HVDC electricity interconnections; operation of multi-vendor VSC-HVDC
systems; upgrading of multi-terminal HVDC systems using innovative components;
innovative repowering of AC transmission systems; and superconductor cables for
HVDC grids. The experimental results will be integrated into the European impact
analyses and form the basis for development of the proposed North Sea grid [115].
The European Commission will provide €35.5 million (i.e. 57%) out of the total project
budget of €63 million between 2014 and 2018.
MEDOW - is a Marie Curie Initial Training Network consisting of 11 partners (5
universities and 6 industrial organisations), intended to train early-stage researchers
across Europe in the area of DC grids and facilitate research, development and
demonstration of DC grids. A DC grid based on multi-terminal voltage source converter
technology is an emerging technology, which is suitable for integration of offshore wind
farms. The four research areas are connection of offshore wind power to DC grids,
investigation of voltage source converter for DC grids, relaying protection, and
interactions between AC/DC grids. The European Commission will provide €3.9 million
euros to the MEDOW project between 2013 and 2017 [141].
E-HIGHWAY 2050 - is a collaborative research and development project between
European Network of Transmission System Operators for Electricity (ENTSO-E) and
major industry and academic partners. The project is intended to plan a 2050 European
electricity transmission infrastructure that would facilitate transfer of renewable
electricity supply to consumers and encourage market integration between the
different countries. The European Commission will provide €8.9 million out of the total
project budget of €13 million between September 2012 and December 2015 [142],
[143].
TWENTIES - is a research and demonstration project carried out by 6 transmission
system operators (in Belgium, Denmark, France, Germany, the Netherlands and
Spain), 2 generator companies, 5 manufacturers and research organisations. The
project demonstrated new technologies and innovative control strategies to facilitate
the integration of wind power and other renewable generation sources into electricity
grids. The European Commission provided €31.8 million out of the total project budget
of €56.8 million between April 2010 and September 2013 [144].
31
REALISEGRID – is a research project carried out by 20 partners (including four
transmission system operators, an original equipment manufacturer, several research
centres and universities) from 9 countries in Europe. The project developed a set of
methods and tools to assess how the electricity transmission infrastructure should be
developed to achieve the EU’s renewable energy targets. The project had a total
budget of €4.3million and was partly funded by European Commission from September
2008 to May 2011 [145], [146].
4.3.2 Intelligent Energy Europe (IEE) Programme
The Intelligent Energy Europe (IEE) Programme was established by the European Agency for
Competitiveness and Innovation and provides research funds to address non-technical
barriers to the development of wind energy in Europe. The key IEE projects related to the
development of offshore grids are:
NorthSeaGrid – was led by 3E consultants in collaboration with 5 partners. The project
defined three case studies to represent building blocks for the development of an
offshore grid in the North Sea. These are: the German Blight (between the grids of
Denmark, Germany and the Netherlands), UK-Benelux (i.e. Belgium, the Netherlands,
and United Kingdom), and UK-Norway (i.e. Norway and United Kingdom). The three
cases were utilised to evaluate the risks and uncertainties of an offshore grid to the
different countries and propose solutions to address political barriers to the
development of offshore grids [147], [148]. The project started in May 2012 and ended
in April 2015 with a total budget of €1.4 million and the European Commission provided
75% of the project costs [149].
GridTech – is a research project carried out by 14 partners to develop different cost-
benefit methods to identify the most suitable technologies for the integration of large
renewable generation and storage systems into the European transmission grid. The
project started in May 2012 and ended in April 2015 with a total budget of €1.96 million
and the European Commission provided 75% of the project costs [150].
OffshoreGrid – is a techno-economic study of offshore grids in Northern Europe with
focus on the regions around the Baltic Sea, the North Sea, the English Channel and
the Irish Sea. The OffshoreGrid consortium consisted of 8 industry and academic
partners. The project started in May 2009 and ended in October 2011 with a total
budget of €1.4 million and the European Commission contributed 75% of the project
costs [151].
4.3.3 Horizon 2020 Programme
Horizon 2020 is the new EU funding instrument for research and innovation programmes, with
a budget of €5.9 billion for energy projects running from 2014 to 2020 [152]. A major Horizon
2020 projects related to the development of offshore HVDC grids is:
PROMOTioN – is a research project to develop and demonstrate three key
technologies for offshore grid networks. These are: (i) diode rectifier offshore
converters; (ii) multi-vendor high-voltage direct current grid protection system; and (iii)
full power testing of HVDC circuit breakers. The PROMOTioN consortium consists of
34 partners from 11 countries and is led by DNV-GL. The project is funded from
January 2016 to December 2019, with a total cost of €51.7 million, of which the EU
contribution is €39.3 million [153].
32
5 Summary
The North Sea Grid is a concept that is intended to transfer the power generated from offshore
wind farms installed in the North Sea to land and interconnect the grids of adjacent countries.
HVDC will be the key technology for submarine electrical power transmission in the proposed
North Sea Grid. LCC-HVDC is mature and suitable interconnection of transmission girds of
different countries. VSC-HVDC is suitable for offshore wind power transmission. The major
components of the HVDC networks of the proposed North Sea Grid are offshore converter
platforms, submarine power cables and onshore converter stations.
5.1 Research Opportunities
The implementation of meshed HVDC offshore grids has been hindered by high cost of
offshore VSC platforms, lack of experience with HVDC protection systems, and absence of
interoperability and multi-vendor compatibility of equipment. Strategic development of the
proposed North Sea grid sets a number of research opportunities in the following technical
aspects:
Diode rectifier concept – is a new concept that is intended to facilitate uni-directional
power transmission from offshore wind farms to onshore grids, using multiple diode
rectifier units connected through HVDC cables. The diode rectifier concept will occupy
less space, have lower transmission losses and reduced cost than offshore VSC
platforms with comparable power ratings [154]. A major limitation of this concept is in
the design of AC voltage control strategies for the offshore grid. Research projects are
required to demonstrate the ability of different wind turbine generator types to regulate
the offshore AC voltage for improved power transmission using the diode rectifier units.
Full scale testing of HVDC circuit breakers – will be required to demonstrate the
effectiveness of fault clearance equipment and protection systems in HVDC networks.
When a pole-to-pole fault occurs in a HVDC network, the DC voltage collapses in less
than 10 ms [155]. The short-circuit currents in the HVDC network will be influenced by
contributions from capacitors, charged cables, lighting impulses from overhead lines
and fault-current infeed from the AC side of HVDC converters. Full scale testing of
HVDC breakers will eliminate barriers to the interruption of DC fault currents in 5 ms.
Interoperability and multi-vendor compatibility of equipment – demonstration projects
are required to test the potential interactions between the control systems of HVDC
equipment supplied by different manufacturers. Also, research projects will be required
to test the effectiveness of meshed HVDC offshore grids with multiple HVDC
equipment, including VSCs, diode rectifier units, HVDC breakers, DC current flow
devices and DC/DC converters.
5.2 Conclusions
This HubNet Position Paper describes the proposed North Sea Grid, reviews the basic
principles of high voltage direct current (HVDC) transmission, highlights the potential
opportunities for UK research and innovation and complements the technologies section of
National Grid’s Electricity Ten Year Statement. There is a strong regulatory encouragement
for UK participation in the North Sea Grid. HVDC converter controllers and modular multilevel
converter submodule designs were described to complement the technologies annex of
National Grid’s Electricity Ten Year Statement. The proposed North Sea Grid could help to
lower electricity supply prices, reduce the cost of delivering security of supply and support the
decarbonisation of electricity supplies in the EU.
33
APPENDICES
A. Summary of concluded OFTO Tenders (information taken from [16]) Name Installed
Capacity (MW)
Transfer Value (£million)
Licence Granted (Year)
Name Installed Capacity (MW)
Transfer Value (£million)
Licence Granted (Year)
Barrow 90 33.6 2011 Walney 1
184
105.4 2011
Greater Gabbard
500 317 2013 Walney 2
184
109.8 2012
Gunfleet Sands 1&2
173 49.5 2011 Lincs 270
307.7 2014
Ormonde 150 103.9 2012 London Array
630
459 2013
Robin Rig East & West
180 65.5 2011 West of Duddon Sands
374
296.2 2014
Sheringham Shoal
315 193.1 2013 Gwnyt y Mor
574 352 2015
Thanet
300 164 2014 Total 3942 2557 -
34
B. Potential Interactions between HVAC and HVDC Systems In the UK, electricity is mainly generated and transmitted using alternating current (AC) [23].
Direct current (DC) is not so widely used and to date has been applied in a small number of
submarine electricity interconnections [116], [117]. It is anticipated that by 2020, more HVDC
systems would be connected to the UK electricity transmission system to form a mixed AC-
DC system [6], [26]. The two major types of mixed AC-DC systems are AC grids with parallel
AC and DC transmission systems and DC grids with separate AC systems [156].
B.1 Change in UK Generation Mix
Since 2011, 15 power plants with a total generation capacity of about 13 GW have been closed
or partially closed in the UK, due to environmental regulations, age, changing market
conditions and limited investments [157]. By 2020, it is expected that about 9 GW of new
electricity interconnection capacity and 4 GW of offshore wind generation capacity will be
connected through HVDC schemes to the UK’s transmission system to replace the
decommissioned power plants [21], [26], [117]. Figure B-1 shows the installed capacities of
generation sources in the Gone Green Scenario of the 2015 UK Future Energy Scenarios [14].
The dynamic operation of power systems depends on the type and amount of generation
connected to it, as well as the nature of demand taken from it [158]. In Figure B-1, the installed
offshore wind capacity is expected to increase to about 30 GW by 2030. Many of the offshore
wind farms will be connected to the UK electricity system through HVDC transmission.
B.2 Consequence of Change in UK Generation Mix
The change in the UK generation mix will result in a reduction of system strength and pose
risk to the operation and control of the power system. The strength of a power system is a
measure of its ability to maintain stable operation during a grid disturbances such as switching
events, faults on transmission lines, loss of generation or load. The two indicators of system
strength are system inertia and short-circuit level [118], [158].
Figure B-1: Installed generation capacities in the UK 2015 Gone Green Scenario [14].
35
B.2.1 System Inertia
The inertia of a power system is a measure of the rotating mass of generating units and
electrical motors operating [158], [159]. It determines the response of the power system to
frequency disturbances due to a sudden loss of generation or load [160]. Variable speed wind
turbines and HVDC systems use power electronic converters to decouple the frequency of
adjacent AC systems and do not contribute to the mechanical inertia of AC systems. As more
renewable generation and electricity interconnections replace large synchronous generators,
the system inertia reduces [158].
During a frequency disturbance, a power system with low inertia will have a higher rate of
change of frequency (RoCoF) and require additional energy to contain the frequency within
operational limits than a system with high inertia. This increase in the RoCoF may result in
unintended trip of the loss of mains relay of distributed generators. Also, the actions required
to contain the frequency would need to take place more rapidly. Energy sources connected
through HVDC converters fitted with auxiliary frequency support controls are able to provide
additional power to AC systems with low-inertia, thereby increasing the system strength [158].
B.2.2 Short-Circuit Level
The short-circuit level of a power system is the maximum fault current that will flow in the
system during a three-phase fault. It is inversely proportional to the source impedance and
determines the response of the power system to switching events or faults on the transmission
system [118], [158]. The short circuit current contribution of variable speed wind turbines with
fully-rated converters and VSC-HVDC systems is limited by the rated capacity of their power
electronic converters. As more variable speed wind turbines and HVDC systems replace large
synchronous power plants, the short-circuit level reduces [158], [161].
During a grid disturbance, a system with low short-circuit level will experience larger voltage
dips and longer voltage recovery periods than a system with a high short-circuit level. The
reduction in short circuit level can change the type and level of harmonics on the system, result
in the incorrect operation of protection devices in the power system and increase the potential
of commutation failures in LCC-HVDC systems. VSC-HVDC systems may be controlled to
support AC systems with low short-circuit levels during AC faults [88], [162], [163].
B.3 AC Grids with Parallel AC and DC Transmission Systems
Figure B-2 shows two AC systems interconnected through an HVAC transmission line in
parallel with an HVDC transmission system. The AC frequency is the same in the two HVDC
stations and a power imbalance in one of the AC systems cannot be alleviated by HVDC
control since both ends of the HVDC circuit are in the same grid. However, this HVDC system
can mitigate an existing bottleneck on the AC side [164].
HVDC Cable
HVDC Cable
X
HVAC Transmission Line
AC
System 1
AC
System 2
V1∠δ1 V2∠δ2
Figure B-2: AC Grid with parallel HVAC and HVDC transmission system
36
The principles applied in the parallel AC and DC configuration shown in Figure B-2 will be
used in the Western Link project in order to reinforce the UK electricity transmission system
by 2016 [165]. The Western Link will use LCC–HVDC technology together with underground
and submarine cables and have a rated capacity of 2200 MW at ± 600 kV [23], [166].
B.3.1 Operation of a Parallel HVAC and HVDC System
Parallel HVAC and HVDC systems can use the dynamic response characteristics of their
HVDC systems to solve HVAC power system stability issues such as voltage and rotor angle
stability [6]. Assuming there are no power losses in the parallel AC-DC system shown in Figure
B-2, the steady-state active power, P, transferred between the two AC systems is [167]:
𝑃 = 𝑃𝐴𝐶 + 𝑃𝐷𝐶 (1)
where PDC is the active power flow through the HVDC circuit and PAC is the active power
through the HVAC transmission line. PAC is also written as:
𝑃𝐴𝐶 =
𝑉1 ∙ 𝑉2 sin 𝛿
𝑋 (2)
where V1 the AC voltages of system 1, V2 is the AC voltage of system 2, X is the equivalent
impedance of the AC transmission line and δ is the difference between the phase angles of
bus voltages of the two AC systems.
For a given value of P, an increase in PDC will result in a reduction of both the PAC and the
phase angle difference δ, according to Equations (1) and (2). This reduction of phase angle
difference will improve the angle stability of the mixed AC-DC system, reduce the loading
capacity of the AC network components and minimise transmission constraints on the AC
system [167].
The reactive power Q1 at the terminals of the AC System 1 is:
𝑄1 =
𝑉1(𝑉1 − 𝑉2 cos𝛿)
𝑋 (3)
In addition to transferring real power between AC systems, VSC-HVDC schemes can also
operate as two separate advanced Static Var Compensators (STATCOM) when they have
some apparent power capacity. For example during an outage of the dc cable or transmission
line, VSCs can use their reactive power capability to support the AC voltage. This capability is
very important for AC voltage control in weak AC systems like offshore wind farms and will
help to maintain AC voltage stability during grid disturbances [168].
B.4 DC Grids with Separate AC Systems
A DC grid would facilitate the transfer of power generated from offshore wind farms to land
and interconnect the grids of separate AC systems. Figure B-3 shows a 3-terminal HVDC grid
which connects an offshore wind farm to a main AC grid and another AC system. Variable
speed wind turbines do not inherently contribute to the inertia of AC grids. The offshore AC
grid shown in Figure B-3 is an example of a system with low system inertia due to the lack of
directly connected motors or generators. Variable speed wind turbines fitted with auxiliary
control systems are capable of transferring additional active power to disturbed AC grids, using
the kinetic energy stored in their rotating mass. The VSCs of DC grids with separate AC
systems have the capability to provide voltage support services to the different AC grids [164].
37
B.5 Frequency Support Characteristics of Mixed AC-DC Systems
Figure B-4 shows a typical frequency transient for the loss of a 1320 MW generation loss on
the GB power system [169]. The maximum rate of change of frequency defined by the National
Grid is 0.125 Hz/s and the maximum frequency deviations are +0.5Hz and -0.8Hz [170].
When multi-terminal HVDC schemes replace synchronous generators of main AC grids, the
level of inertia present in the AC system reduces. Low-inertia AC grids have a higher rate of
change of frequency (RoCoF), require a larger amount of additional power from individual
responding generation units and are less stable during a grid disturbance than AC systems
with high inertia [160], [165].
The HVDC grid show in Figure B-3 is connected to separate AC systems and has the capability
to mitigate the impact of changes in system inertia. This frequency support can be delivered
through synthetic inertia response, active power frequency response and damping of low
frequency power oscillations [165].
B.5.1 Synthetic Inertia Response
Synthetic inertia response uses rapid injection of power from the different energy sources of
mixed AC-DC systems to limit the rate of change of frequency (RoCoF) of main AC grids. The
additional power is taken from the kinetic energy in the rotating mass of wind turbines. If the
initial RoCoF is high enough, it will cause unintended operation of loss of mains protection
relays in the power system and result in cascaded tripping of distributed generators.
Figure B-4: Frequency deviation following a loss of 1320 MW generation [169]
Wind Farm
Converter
Main AC
Grid
Other
AC System
Offshore AC
grid
PMSG
Grid Side
Converter 1
Offshore OnshoreOffshore
Wind Turbine
PMSG
Full Converter
PMSG
Grid Side
Converter 2
DC cable
3-Terminal
HVDC Grid
Figure B-3: A 3-Terminal HVDC Grid with separate AC systems
38
In Great Britain (GB), the Grid Code requires the protection relays of distributed generators
rated above 5 MW to have a threshold RoCoF setting of 0.125 Hz/s. This RoCoF setting will
be increased to 0.5 Hz/s for synchronous generators by 2018 in response to the anticipated
reduction in system inertia [158]. Mixed AC-DC systems are to use enhanced inertia response
controllers in their power electronic converters in order to limit the RoCoF of the AC grids
[106], [158], [171].
B.5.2 Active Power Frequency Response
Active power frequency response uses the fast control of the power output of the different
generation sources or loads of mixed AC-DC schemes to contain the system frequency
deviation. Frequency containment is a set of actions used to control system frequency to 50
Hz following a loss of generation or demand without exceeding operational limits [158]. HVDC
systems connected to separate AC grids transfer power from one AC system to another and
have the capability to exchange frequency support services between the AC grids.
The active power frequency response from individual responding generation units has to be
delivered quickly enough according to a minimum ramp rate of the generators. The GB Grid
Code requires generator’s active power response to have a maximum delay of 2s and a ramp
rate of 250MW/s following a maximum infeed loss of 1320MW [160]. This is set to increase to
400 MW/s due to anticipated maximum infeed loss of 1800 MW [160]. Furthermore, the
ENTSO-E has proposed a maximum delay of 0.5s for active power response from HVDC
connections [106].
B.5.3 Damping of Low Frequency Power Oscillations
Small disturbances such as changes in demand or voltage cause a change in the speed and
rotor angle of synchronous generators connected to the power system and result in oscillation
of the power flow on the transmission system. These oscillations may damage equipment on
the transmission system and are usually damped by synchronising and damping torques of
synchronous generators connected to the power system [165].
AC systems with low inertia typically have reduced damping capabilities and increased
amplitude of power oscillations than high-inertia systems. The HVDC converters of the
proposed North Sea grid would be required to damp power oscillations in connected AC
networks. The ENTSO-E grid code on operational security defines the network conditions and
frequency range of oscillations which the control schemes of the HVDC systems would
positively damp [106], [172].
B.6 Reactive Power Control and Voltage Support Capability
HVDC converter stations should have the capability to operate at their maximum current,
remain connected to the AC system during normal operation or transient fault conditions and
support the AC voltage during grid disturbances. Table B-1 shows the operational limits of AC
voltages (in per unit) and the minimum time periods for HVDC systems have to remain
connected to AC systems rated up to 400 kV for different synchronous areas of the proposed
North Sea Grid.
Large AC voltage deviations above or below the operational limits (shown in Table B-1) may
damage power transmission equipment [173]. HVDC converters have the capability to inject
reactive power at their connection point to return the AC voltage to nominal operating values.
During a grid disturbance, the two major parameters that determine the voltage support
characteristics of a VSC-HVDC converter are the U-Q/Pmax profile and reactive power control
mode.
39
Table B-1: Operational limits of power systems rated up to 400 KV during normal operation
Synchronous
Area
AC Voltage Range
(pu)
Time Period for HVDC Converter
operation
Continental
Europe
0.8500 – 1.0500 Unlimited
1.0500 – 1.0875 Greater than 60 minutes
1.0875 – 1.1000 60 minutes
Nordic 0.9000 – 1.0500 Unlimited
1.0500 – 1.1000 60 minutes
Great Britain 0.9000 – 1.0500 Unlimited
1.0500 – 1.1000 15 minutes
Continental Europe - Belgium, Germany, the Netherlands
Nordic – Norway, Denmark
B.6.1 U-Q/Pmax Profile
A U-Q/Pmax profile specifies the reactive power limits of a HVDC converter station during
operation at its maximum active power transmission capacity. The ENTSO-E draft network
code on HVDC connections describes the U-Q/Pmax profile of voltage source converters.
Figure B-5 shows the U-Q/Pmax profile of a HVDC converter station and Table B-2 shows the
AC voltage range and the range of Q/Pmax of the different synchronous areas of the proposed
North Sea grid.
The ENTSO-E expects that the HVDC converter stations would operate within the boundaries
of the inner envelope of the U-Q/Pmax profile shown in Figure B-5. The positon of this inner
envelope shall lie within the limits of the fixed outer envelope. The dimensions of the inner
envelope shown in Figure B-5 must be within the operational limits specified in the Table B-2.
Consumption (lead) Production (lag)
-0.5 -0.4 -0.3 -0.2 -0.1 0-0.6 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Q/Pmax
0.8
0.9
1.0
1.1
1.2
U (p.u.)
Inner envelope
Fixed outer envelope
Range of Q/Pmax
AC Voltage range
Figure B-5: The U-Q/Pmax profile of a VSC-HVDC converter station
40
Table B-2: Range of Q/Pmax and AC voltage range of different synchronous areas [106]
Synchronous Area Range of Q/Pmax AC voltage range
(pu)
Continental Europe 0.95 0.225
Nordic 0.95 0.150
Great Britain 0.95 0.100
Continental Europe - Belgium, Germany, the Netherlands
Nordic – Norway, Denmark
B.6.2 Reactive Power Control Modes
The short circuit current capability of VSC-HVDC schemes depends on their control mode,
operating point and control strategy [161]. The three control modes for AC voltage support
from the VSCs are AC voltage control, reactive power control and power factor control. VSCs
may operate using one or more of the three control modes [106].
AC voltage control enables the HVDC converter to maintain a set-point voltage at the AC
connection point within a specific operational limit through reactive power control. During a
step change in AC voltage, the HVDC converters would achieve 90 % of the change in reactive
power within a short time in the range of 0.1 – 10 seconds and settle at the new value of
reactive power within 60 seconds. Reactive power control mode enables transmission system
operators to specify a reactive power range in MVAr or in % of maximum reactive power for
the HVDC converters at any given time. In power factor control mode, the HVDC converters
regulate the power factor at their connection point to a target value [106].
B.7 Fault-Ride-Through Capability
HVDC converters are required to remain connected to the power system during a transient
AC fault and continue stable operation after the system has recovered from the fault. This
fault-ride-through capability limits the potential loss of more generation sources after a fault
on the power system and avoids more severe disturbances.
The fault-ride-through characteristics of an HVDC converter station is described using a
voltage-against-time profile. This profile represents the lower limit of the evolution of the
phase-to-phase AC voltages (in per unit) before, during and after the fault. Figure B-6 shows
the voltage-against-time profile of a HVDC converter station during a three-phase fault.
Uret
Ublock
0 tclear trec1
Urec1
Urec2
1.0
trec2 t/sec
U/p.u.
Figure B-6: Fault-Ride-Through profile of a HVDC converter station. Uret is the retained voltage at the connection point of the converter to the AC system during a fault. tclear is the duration of the fault. Urec1 and trec1 specify a point of lower limits of
the voltage recovery following fault clearance. Ublock is the blocking voltage at the connection point. The time values are measured from the instant the fault occurs [106].
41
Transmission system operators may specify a blocking voltage (Ublock) for the HVDC converter
station to remain connected to the AC system with no active and reactive power contribution
for a very short time [106]. Table B-3 is a summary of the parameters of the voltage-against-
time profile shown in Figure B-6.
Table B-3: Parameters of the voltage-against-time profile [106]
Voltage parameters (pu) Time parameters (seconds)
Uret 0 – 0.3 tclear 0.14 – 0.25
Urec1 0.25 – 0.85 trec1 1.50 – 2.5
Urec2 0.85 – 0.90 trec2 trec1 – 10.0
The retained voltage (Uret) and fault clearance time (tclear) specified in Table B-3 affect the
design of protection schemes of HVDC converters. It is expected that the operation of the
protection schemes would not interfere with the fault ride through characteristics of the
converters.
B.8 HVDC System Robustness
According to the ENTSO-E draft network code on HVDC connections, HVDC, VSCs of mixed
AC and DC system are to have the capability to find stable operating points with a minimum
change in active power flow and voltage levels, during and after any planned or unplanned
changes in the network. The changes in the system may include loss of communication,
reconfiguration of HVDC or AC system, changes in load flow, changes of control mode, control
system failure, trip of one pole or converter etc.
When several HVDC converter stations and other plants and equipment are within close
electrical proximity, there must be no adverse interference with the operation of other HVDC
systems, power generation modules or any protection devices in the adjacent AC network.
During energization or synchronization of HVDC converters to AC networks or during the
connection of an energized HVDC converter to a DC grid, the HVDC converters are required
to limit voltage changes within 5 per cent of the pre-synchronization voltage. Also, the HVDC
converters shall be capable of contributing to electrical damping of sub-synchronous torsional
frequencies [106].
B.9 Infeed Loss Limit
The infeed loss limit of a power system is a measure of the amount of additional power which
transmission system operators will use to replace energy lost through a fault, either through
failure of a circuit or shut down of a power station. This additional power is obtained from
responding generation units, HVDC systems, energy storage plants and fast demand side
response [160]. Table B-4 shows the expected wind capacities and infeed loss limits of six
countries.
By 2020, the infeed loss limit in the UK will be 1.8 GW and that of Germany, Belgium and the
Netherlands will be 3 GW [174]. The infeed loss limits shown in the Table B-4 is a key
parameter which will affect the design of the HVDC networks of the proposed North Sea grid.
The rated capacity of any single HVDC circuit shall not exceed the infeed loss limits of the
interconnected countries.
42
Table B-4: Expected Wind Capacities and Infeed loss limits (information taken from [4], [174]])
Country Wind Capacity 2020
[4] (GW)
Wind Capacity 2030
[4] (GW)
Infeed Loss Limit
[174] (GW)
Great Britain 11.5 38.5 1.8
Belgium 2 4 3 Denmark 1 3.4 *1.36
The Netherlands 2 12 3 Germany 10 24 3
Norway 0 1 *1.36 Total 25.5 82.9
*Sweden, Norway, Finland and Denmark share frequency control reserve of 1.16 GW against infeed loss risk of 1.36 GW
B.10 Integration of Energy Storage Schemes through HVDC Systems
The major technology for transmission-connected energy storage schemes in the UK is
pumped hydro-electric systems. Pumped storage plants use excess electricity to pump water
from a lower reservoir to an upper reservoir, and operate as a generator during periods of
peak demand by reversing the flow of water.
By 2018, Gaelectric plans to build a 1500 MW pumped hydro plant in Glinsk, Ireland. The plant
is intended to have a daily storage capacity of 6 GWh and transfer power to the UK through
underground and submarine HVDC cables rated at 1.5 GW and ±500 kV [175]. Also, Norway
plans to develop about 18 GW of new hydro power generation and pumped installation
capacity by 2030 [176]. The transmission system operators of the UK (National Grid) and
Norway (Statnett) intend to install a 1400 MW submarine HVDC interconnector across the
North Sea, for energy balancing and trading between the two countries by 2020 [177], [178].
By 2020, the NordLink HVDC project will use VSC-HVDC technology for electricity
interconnection and trading between the grids of Germany and Norway. The HVDC scheme
will have a rated capacity of 1400 MW, operate at a DC voltage of ±525 kV and use about 516
km of mass impregnated cables for subsea power transmission [179]. These HVDC
transmission systems would facilitate the development of the proposed North Sea grid.
43
C. Funding Landscape for the Proposed North Sea Grid
Figure C-1 illustrates how different organisations support the proposal to develop offshore
wind power and electricity transmission systems in the North across different technology readiness levels [120].
Figure C-1: Funding Landscape for the proposed North Sea Grid (adapted from [110])
44
D. EPSRC-funded projects with work packages which are related grid connection of offshore wind farms through submarine power transmission
networks (with grant value above £100 K)
Title Lead Research Organisation Start Date
End Date Grant Value (£)
1 Mitigating the effect of low inertia and low short-circuit level in HVDC-rich AC grids Cardiff University Dec2014 Dec2017 295 K
2 HubNet: Research Leadership and Networking for Energy Networks Imperial College London June 2011 May 2016 4,746 K
3 Enhanced Renewable Integration through Flexible Transmission Options (ERIFT) Imperial College London Apr2013 Mar2016 880 K
4 MTVN: Multi-Terminal VSC-HVDC Networks - Grid Control The University of Manchester Oct2014 Oct2017 534 K
5 FCL/B: An Integrated VSC-HVDC Fault Current Limiter/Breaker The University of Manchester July2014 July2017 640 K
6 DC Networks with DC/DC Converters for Integration of Large Renewable Sources University of Aberdeen May2013 May2016 734 K
7 Towards Enhanced HVDC Cable Systems University of Southampton Oct 2014 Oct 2018 1,113 K
8 Supergen Wind Hub University of Strathclyde June 2014 June 2019 2,967 K
Total 11,909 K
45
E. Technology Strategy Board (TSB)-funded projects with work packages which are related to grid connection of offshore wind farms through submarine power
transmission networks (with grant value above £100 K)
Title Lead Research Organisation Start Date End Date Grant Value (£)
1 TLPWIND UK: Driving the cost down of offshore wind in UK Waters Iberdrola Engineering and Construction UK Limited Sep 2014 Feb 2016 580 K
2 Neptune Offshore Access System Submarine Technology Limited Oct 2013 Mar 2015 248 K
3 Supply Design of High Efficiency, High Density DC Power Demonstrator Supply Design Limited Feb 2014 Aug 2015 168 K
Total 996 K
46
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