Planning and Operation of the North Sea Grid

Transcription

1 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: Version Control: Version Date Comments /07/2015 Draft version for peer review /03/2016 Revised in response to peer review comments /05/2016 Final version for publication Status: Published Date Issued: 05/05/2016 Available from i

2 CONTENTS About HubNet...iii 1. INTRODUCTION North Sea Grid Proposals Drivers for Development of Offshore Grids in the UK Submarine Cables Opportunities for UK Research and Innovation TOPOLOGIES OF THE NORTH SEA GRID Submarine Electrical Power Systems Status of HVDC technology National Strategies Development of Electricity Interconnectors in the North Sea Visions of the future North Sea Grid OPERATION OF THE NORTH SEA GRID Physical Structure of VSCs Converter Bridges Operating Characteristics of a VSC VSC Topologies HVDC Configuration and Operating Modes Multi-Terminal HVDC Systems Modelling and Testing of MTDC Grids Potential Interactions between HVAC and HVDC systems OVERVIEW OF SUPPORT FOR THE DEVELOPMENT OF THE NORTH SEA GRID Regions National European Summary Research Opportunities Conclusions APPENDICES REFERENCES ii

3 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. This hub will provide research leadership in the field through the publication of in-depth position papers written by leaders in the field and the organisation of workshops and other mechanisms for the exchange of ideas between researchers and between researchers, industry and the public sector. HubNet also aims to spur the development of innovative solutions by sponsoring speculative research. The activities of the members of the hub will focus on seven areas that have been identified as key to the development of future energy networks: 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. The HubNet Association is a free-to-join grouping of researchers and research users. Join via the HubNet Registration tab at to get access to working document versions of positions papers, an archive of workshop and symposium presentations and to receive notification of future events. iii

4 Planning and Operation of the North Sea Grid 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 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 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) 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]. 1

5 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] 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. Figure 1: Map of existing and proposed GB electricity interconnector project [26] 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]. 2

6 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 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 Array Cables[17], Export Cables[17], [29] Main [30] Location HVAC HVDC MVAC 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 3

7 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 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 [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 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] 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] 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. 4

8 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. 5

9 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 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 kv for connection to an offshore converter station. Offshore AC Substation Offshore Converter Platform 80 km Converter Station High Voltage Alternating Current Electrical Power Grid North Sea Medium Voltage Alternating Current High Voltage Alternating Current High Voltage Direct Current (HVDC) Onshore Figure 2: Simplified electrical system of an offshore wind farm. Copyright GE Grid 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 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. 6

10 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 heavylift 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] 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 massimpregnated (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 mm 2 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 MI (PPLP Technology) XLPE- Extruded Cross Linked Polyethylene MI Mass Impregnated; PPLP Paper Polypropylene Laminate 7

11 2.2.3 Onshore Converter Stations There are two main HVDC converter technologies: line commutated converter (LCC), and selfcommutated 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 ± ± ±1100 VSC 0.5 ± 200 *Converters have one pole 1 ± * 2 ± 500 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]. 8

12 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 Table 3 is summary of the existing and proposed subsea interconnection capacities to be installed in the North Sea by HVDC Interconnectors Existing Proposed 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 Norway (NO) North Sea 3 7 Denmark (DK) 10 Great Britain (GB) The Netherlands (NL) Belgium (BE) Germany (DE) Figure 3: Existing and proposed HVDC interconnectors in the North Sea by Copyright d-maps.com 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& ±250 LCC 2 DK-NO Skagerrak LCC 3 NL-NO NorNed ±450 LCC 4 GB-NL BritNed ±450 LCC 5 DK-NO Skagerrak VSC 6 BE-GB NEMO ±250 VSC 7 DE-NO Nord.Link ±500 VSC 8 DK-NL COBRA ±320 VSC 9 GB-NO NSN ±500 LCC 10 DK-GB Viking Link Total BE-Belgium; DE-Germany; DK-Denmark; GB-Great Britain; NL-The Netherlands; NO-Norway 9

13 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 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 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-topoint 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]. 10

14 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. AC System Transformer Phase Reactor AC Filters Converter Station A DC Cable or Overhaed Line DC Capacitor Converter Station B AC System Figure 4: VSC-HVDC transmission scheme 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] 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. 11

15 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 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. XL IL Receiving End Vac ΔV (a) Vout Sending End 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 = V out sin δ (1) V X ac L Q = V ac V out cosδ X L V ac (2) S = P 2 + Q 2 (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. Imaginary Part Vout Vac ΔV Real Part Figure 5: Two AC voltage sources connected through an ideal reactor (a) Schematic diagram (b) Phasor diagram 0 δ (b) I 12

16 Vac = 0.9 pu Q [p.u] Supplying Vars Vac = 1.0 pu Vac = 1.1 pu P [p.u] Maximum Active Power Limit Maximum AC Voltage Limit Maximum IGBT Current Limit Absorbing 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) 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. Figure 7: Output voltage waveforms from the two-level, three-level and multilevel topology of VSCs [72] 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 2 V dc and 1 2 V dc between the midpoint of the DC capacitor and the point a shown in Figure 8. 13

17 Idc List of symbols Interface Transformer AC Filter Phase Reactor Iac Vac ΔV IL Vout a 1 Vdc Vdc Vdc IGBT Valve 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 Figure 8: One-phase of a two-level VSC 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] 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 2 V dc, 0 and 1 2 V dc) 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. + 1 Vdc 2 Diode Valve Phase Reactor a 0 Vdc Vdc IGBT Valve Figure 9: One-phase of a three-level neutral point clamped VSC 14

18 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 multivalve 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]. Upper-arm Voltage + - SM 1,a SM 2,a SM N,a SM 1,b SM 2,b SM N,b SM Level,phase SM 2,c SM N,c + Types of Submodule Circuits + V SM - S1 S1 S2 v c (b) Half-Bridge S3 + - V c V b V a ia + i b SM N+1,a i c SM N+1,b Arm reactors SM Level+1,phase V dc + V SM - S2 (c) v c + - S4 Full -Bridge Lower-arm Voltage SM N+2,a SM N+2,b SM N+2,c S1 v c + v c + S3 - SM 2N,a SM 2N,b SM 2N,c Phase arm Multi-valve arm Submodule (SM) (a) Three-phase Topology I dc - V SM S2 (d) - S5 Clamp Double Figure 10: Schematic diagram of an MMC-HVDC Scheme (a) Three-phase Topology (b) Half-bridge submodule (c) Fullbridge submodule (d) Clamp double submodule - S4 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]. 15

19 3.3.4 Submodule Circuits The three main types of switching circuits in the submodules of the MMCs are half-bridge, fullbridge 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] 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) Estlink (Estonia-Finland) Borwin 1 (Germany) Cross Sound (USA) Murray Link (Australia) Trans Bay (USA) Borwin 2 (Germany) Dolwin 1 (Germany) Dolwin 3 (Germany) Converter Topology Ratings per converter Capacity Voltage (MW) (kv) Two-level 350 ±150 Two-level 400 ±150 Three-level 330 ±150 Three-level 220 ±150 Modular Multilevel Modular Multilevel Cascaded Two-Level 400 ± ± ± ±320 Application Electricity interconnection and grid reinforcement Connection of offshore wind farms Electricity interconnection and grid reinforcement Electricity interconnection and grid reinforcement Electricity interconnection and grid reinforcement Connection of offshore wind farms Connection of offshore wind farms Connection of offshore wind farms Date

20 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 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 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] 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 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. 17

21 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 dioderectifier 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 dioderectifier and an onshore VSC. A recent press release indicated that this new offshore converters are likely to be available by 2016 [89]. 18

22 Table 6: Configuration and Operating Modes of HVDC Systems HVDC Scheme Configuration Number of Converters Number of Cables Rectifier Inverter HVDC LVDC Availability 1. Back-to-Back Zero output during pole outages. Figure 11: Back-to-back HVDC scheme with mid-point ground HVDC Cable 2. Asymmetrical Monopole Metallic return Zero output during cable or pole outages. Figure 12: Asymmetric monopolar HVDC scheme with ground return or metallic return HVDC Cable (+ve) 3. Symmetrical Monopole HVDC Cable (-ve) Zero output during cable or pole outages. Figure 13: Symmetric monopolar HVDC scheme with mid-point ground HVDC Cable HVDC Cable Half capacity during pole outages. Zero output during cable outages. 4. Bipole Figure 14: Bipole HVDC scheme with mid-point ground HVDC Cable Metallic-return transfer breaker Half capacity during cable or pole outages. HVDC Cable Figure 15: Bipole HVDC scheme with metallic return for pole outage 5. Diode-Rectifier w ith VSC Inverter HVDC Cable Diode rectifier HVDC Cable Zero output during cable or pole outages. Figure 16: HVDC scheme with uncontrolled diode-rectifier and VSC inverter 19

23 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 multiterminal HVDC (MTDC) system [91] [93] 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. HVDC Grid Controller Signals Set-points Signals Set-points Signals Set-points VSC1 VSC3 VSC2 Figure 17: Signal flow between the HVDC Grid Controller and three voltage source converter stations 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. 20

24 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. R1 RN Voltage Source S1 SN DC Cable or Line 1 DC Cable or Line 1 VSC1 DC Cable or Line 2 VSC3 VSC1 DC Cable or Line 2 VSC3 DC Cable or Line 3 DC Cable or Line 3 VSC2 (a) 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. VSC2 Figure 18: Direct Current Control using (a) Switched Resistors and (b) Voltage Insertion. (b) 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. Varistor Stack of IGBT (a) Commutation Circuit Metal Contacts (b) Varistor L Residual DC circuit breaker Mechanical Switch Load commutation switch Series Inductor Main DC Circuit Breaker Figure 19: Structure of different types of DC circuit breakers (a) Resonant (b) Solid state (c) Hybrid (c) 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 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]. 21

25 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] 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. = Converter Station HVAC MW ± 320 kv MW HVDC 1 GW = 1 GW ± 320 kv = 400 kv AC Hub = ± 320 kv 1 GW MW = 1 GW MW ± 320 kv Figure 20: A Supernode for offshore wind power transmission 22

26 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 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: ; 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] 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 Description (Start date (TC) or Working Group End date) (WG) CIGRE B4-52 HVDC Grids Feasibility Study ( ) CIGRE B4-56 Guidelines for Preparation of Connection (2011 Agreements or Grid Codes for HVDC Grids 2014) CIGRE B4-57 Guide for the Development of Models for HVDC (2011 Converters in a HVDC Grid 2014) CIGRE B4-58 Devices for Load Flow Control and (2011 Methodologies for Direct Voltage Control in a 2014) Meshed HVDC Grid CIGRE B4/B5-59 Control and Protection of HVDC Grids ( ) CIGRE B4-60 Designing HVDC Grids for Optimal Reliability (2011 and Availability Performance 2014) CIGRE B4/C1.65 Recommended voltage for HVDC Grids (2013 CENELEC TC8X European Study Group on Technical Guidelines for DC Grids New CENELEC TC8X WG06 IEC TC-57 WG13 CIM A continuation of the Working Group Power Systems Management and Associated Information Exchange 2015) ( ) Status Report published in [108] To be published Report published in [101] To be published To be published To be published Work in progress Findings published in [94], [107] (2013 Work in progress (2014 Reports available at [109] 23

27 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]. 24

28 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. 25

29 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] 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 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]. 26

30 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 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 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]. 27

31 EPSRC Centre for Doctoral Training in Power Networks at the University of Manchester with a grant of 3.95 million [131], [132] 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 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 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] 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]. 28

32 At present, there are five Electricity NIC projects - two were awarded in 2013 and three were awarded in 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 Multi Terminal Test Environment (MTTE) for HVDC systems Scottish Hydro Electric Transmission Visor Scottish Power Transmission Enhanced Frequency Control Capability Offshore Cable Repair Vessel and Universal Joint Modular Approach to Substation Construction National Grid Electricity Transmission TC Ormonde OFTO Ltd. Scottish Hydro Electric Transmission A collaborative centre to simulate the impact of HVDC technology on electricity network operation and control [137]. New techniques for operating and planning the power system using wide area monitoring systems [137]. To develop new techniques to enhance National Grid s capability to control system frequency [138]. To convert an existing telecom cable repair vessel into a power cable repair vessel and demonstrate a new universal cable jointing system [138]. To develop and trial modular techniques in electrical substation construction through innovation in design and civil engineering [138] Duration (years) 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] 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. 29

33 The EU s support was provided through the 7 th Framework Programme (FP7) and the Intelligent Energy Europe (IEE) Programme from 2007 to In 2014, the two funding programmes were replaced with a Horizon 2020 programme [121] th Framework Programme (FP7) The 7 th 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 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 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]. 30

34 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] 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 costbenefit 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] 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]. 31

35 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. 32

36 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 Walney Greater Walney Gabbard Gunfleet Lincs Sands 1&2 Ormonde London Array Robin Rig West of East & West Duddon Sands Sheringham Gwnyt y Shoal Mor Thanet Total

37 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]. Figure B-1: Installed generation capacities in the UK 2015 Gone Green Scenario [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 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]. 34

38 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]. AC System 1 V1 δ 1 X V2 δ 2 HVAC Transmission Line AC System 2 HVDC Cable HVDC Cable Figure B-2: AC Grid with parallel HVAC and HVDC transmission system 35

39 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 = P AC + P DC (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: P AC = V 1 V 2 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: Q 1 = V 1(V 1 V 2 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]. 36

40 Offshore Wind Turbine PMSG Full Converter Offshore AC grid Offshore Onshore Other AC System PMSG 3-Terminal HVDC Grid Grid Side Converter 1 Wind Farm Converter Grid Side Converter 2 PMSG DC cable Main AC Grid Figure B-3: A 3-Terminal HVDC Grid with separate AC systems 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 Hz/s and the maximum frequency deviations are +0.5Hz and -0.8Hz [170]. Figure B-4: Frequency deviation following a loss of 1320 MW generation [169] 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. 37

41 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 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. 38

42 Table B-1: Operational limits of power systems rated up to 400 KV during normal operation Synchronous Area Continental Europe Nordic Great Britain AC Voltage Range (pu) Time Period for HVDC Converter operation Unlimited Greater than 60 minutes minutes Unlimited minutes Unlimited 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. U (p.u.) 1.2 Fixed outer envelope 1.1 AC Voltage range 1.0 Range of Q/Pmax 0.9 Inner envelope Consumption (lead) Production (lag) Figure B-5: The U-Q/Pmax profile of a VSC-HVDC converter station Q/Pmax 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. 39

43 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 Nordic Great Britain 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 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. U/p.u. 1.0 Urec2 Urec1 Ublock Uret 0 tclear trec1 trec2 t/sec Figure B-6: Fault-Ride-Through profile of a HVDC converter station. U ret is the retained voltage at the connection point of the converter to the AC system during a fault. t clear is the duration of the fault. U rec1 and t rec1 specify a point of lower limits of the voltage recovery following fault clearance. U block is the blocking voltage at the connection point. The time values are measured from the instant the fault occurs [106]. 40

44 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-againsttime profile shown in Figure B-6. Table B-3: Parameters of the voltage-against-time profile [106] Voltage parameters (pu) Time parameters (seconds) Uret tclear Urec trec Urec trec2 trec 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. 41

45 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 Belgium Denmark * 1.36 The Netherlands Germany Norway 0 1 * 1.36 Total *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. 42

46 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]) 43