european offshoregrid site requirements and connection report

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This document contains information, which is proprietary to the “OffshoreGrid” Consortium. Neither this document nor the information contained herein shall be used, duplicated or communicated by any means to any third party, in whole or in parts,

except with prior written consent of the “OffshoreGrid” consortium.

European OffshoreGrid

Site Requirements and Connection Report

Senergy Econnect Project: 2335

Peter McGarley & Simon Cowdroy

July 2010

Agreement n.: EIE/08/780/SI2.528573

Duration May 2009 – November 2011

Co-ordinator: 3E

Supported by:

Document Name: 2335 D5.1 Site Requirements and Connection Report v1.00 PUBLIC.doc 02/08/2010 Page: 2/66

Document information

Document Name: Site Requirements and Connection Report

Document Number: D5.1

Author: Peter McGarley

Date: 28/07/2010

WP: 5

Task: 1

Revision: V1.0

Approved: Simon Cowdroy


Table of contents

1 INTRODUCTION ........................................................................................................................... 5

2 OFFSHOREGRID DESIGN ASSUMPTIONS ............................................................................... 7

2.1 Offshore Wind farm substations .................................................................................................. ...... 7

2.1.1 Offshore Substation specification.................................................................................................. .. ....8

2.2 Available Transmission Technologies .......................................................................................... ...... 8

2.2.1 High Voltage Alternating Current (HVAC) solutions....................................................................... .. ....8

2.2.2 HVAC Cable ..................................................................................................................................... .. ..10

2.2.3 Offshore HVAC Cable ...................................................................................................................... .. ..10

2.2.4 Onshore HVAC Cable ...................................................................................................................... .. ..11

2.2.5 High Voltage Direct Current (HVDC) Solutions .............................................................................. .. ..12

2.2.6 Current Source Converter HVDC Technology ................................................................................ .. ..12

2.2.7 Voltage Source Converter HVDC Technology ................................................................................ .. ..13

2.2.8 HVDC Return Path........................................................................................................................... .. ..14

2.2.9 HVDC Cables ................................................................................................................................... .. ..15

2.2.10 Super Conductors ........................................................................................................................... .. ..16

2.2.11 Gas Insulated Transmission Lines................................................................................................. .. ..16

2.2.12 Switchgear....................................................................................................................................... .. ..16

2.3 System Operator Requirements................................................................................................... ....18

2.3.1 Frequency Control Reserve ............................................................................................................ .. ..18

3 OFFSHOREGRID DESIGN METHODOLOGY ........................................................................... 20

3.1 Defining the OffshoreGrid ............................................................................................................ ....20

3.2 Establishing the offshore project capacities and locations......................................................... ....20

3.3 Assessing On and Offshore Cable Routes ................................................................................... ....20

3.4 Land Fall Requirements ............................................................................................................... ....20

3.5 Asset Redundancy........................................................................................................................ ....21

3.5.1 Number of Transformers ................................................................................................................ .. ..21

3.5.2 Number of AC Circuits .................................................................................................................... .. ..21


3.5.3 DC Monopole or Bipole Design ...................................................................................................... .. ..21

3.6 Cost Inclusions and Exclusions .................................................................................................... ....21

3.7 Offshore substation/hub to shore design.................................................................................... ....22

3.8 Hub to Offshore Project design .................................................................................................... ....22

3.9 Onshore Grid Integration.............................................................................................................. ....23

4 RADIAL SCENARIO 2030 .......................................................................................................... 25

4.1 Radial Scenario 2030 .................................................................................................................. ....25

4.2 Results.......................................................................................................................................... ....25

5 2030 HUBS BASE CASE............................................................................................................ 27

5.1 Economic Hub Assessment Tool .................................................................................................. ....27

5.2 Results.......................................................................................................................................... ....28

6 INTERCONNECTOR T-IN EXAMPLE ........................................................................................ 32

6.1 Limitations of T-in CSC Design ..................................................................................................... ....32

6.2 BritNor – Dogger Bank A Interconnector T-in.............................................................................. ....33

6.2.1 BritNor – Dogger Bank A Interconnector T-in Capital Costs ......................................................... .. ..42

6.3 Nordlink - DanTysk/Sandbank OWF Group T-in.......................................................................... ....42

6.3.1 Nordlink - DanTysk/Sandbank OWF Group T-in Capital Costs ..................................................... .. ..45

7 MESHED OFFSHORE GRID CASE STUDY .............................................................................. 47

7.1 Capital Costs................................................................................................................................. ....47

8 CONCLUSIONS .......................................................................................................................... 57

9 REFERENCES ............................................................................................................................ 66


1 INTRODUCTION

OffshoreGrid is a techno-economic study within the Intelligent Energy Europe programme, aimed at setting out a scientifically derived view of a possible offshore grid serving Northern Europe and also of the regulatory framework necessary to support such an offshore grid. The OffshoreGrid study comprises of ten discrete Work Packages (WP) which are summarised in the bullet points below;

• WP1 – Project management • WP2 – Review of North European Electricity Markets • WP3 – Offshore wind scenarios • WP4 – Scenario definition and version control of WPs 5 & 6 • WP5 – Offshore grid design and investment calculation (this study) • WP6 – Offshore electricity market modelling • WP7 – Transfer to the Mediterranean area • WP8 – Policy recommendations • WP9 – Communication and publication • WP10 – IEE Public Relations

This report represents the first output from Work Package 5 which identifies the site requirements and grid connection methodology for wind and marine energy projects in Northern Europe. This report has drawn on the information and assumptions arising from Work Packages 2, 3 and 4 relating to existing markets, wind resource and future markets respectively. Work Package 5 in conjunction with Work Package 6 will in turn be used as one of the key building blocks in assessing the potential for interconnection to the Mediterranean area and also assembling an appropriate policy framework through WPs 7 and 8 respectively. The key activities in progressing this report are:

• The setting of design assumptions and methodology. • Definition of a Radial Scenario where all offshore projects are built using radial connections to the

onshore transmission system. • The establishment of offshore hubs where clusters of offshore projects share grid connections to the

onshore transmission system. • An analysis of connecting certain projects to planned interconnectors with a T-in design. • The establishment of an initial North European Offshore Grid design (taking into account a base case

2030 scenario and a further three case scenarios from Work Package 4 assuming increments of offshore interconnection) that will be fed into Work Package 6 for economic modelling.

• Calculation of the level of capital cost investment required in order to complete the designs proposed. This study takes into account existing and forecast offshore wind and marine energy projects in Northern Europe and planned interconnectors between neighbouring countries. The scope includes offshore assets only up to the onshore substation where the offshore grid connects to the onshore transmission system. Onshore constraints and the resulting reinforcements required are outside the scope of this study and have not been studied. Section 2 of this report sets out the design assumptions upon which the later designs and topologies have been based. It considers approaches to offshore network topography design and the use of different electricity transmission technologies. Section 3 proposes the design methodology. The initial phase of the study defines a Radial Scenario for 2030 where all of the offshore generation projects are connected to the onshore transmission system via radial links and all of the planned interconnectors are built as point to point between countries without connecting any interconnection of offshore generation. The results are set out in Section 4. This is intended to show a continuation of practice to date where all of the offshore projects and interconnectors are built separately. It is intended that the Radial Scenario set out in Section 4 should provide a benchmark for the purposes of evaluating the subsequent offshore grid designs rather than represent a design proposal. The first increment of offshore grid design proposed within the study is the establishment of offshore hubs, in which projects that are in close geographical proximity to one another could share a grid connection to the onshore transmission system via a common offshore hub. Section 5 describes the methodology used to group


projects into clusters for the purposes of sharing a hub. It also shows the cost differential between the clustered projects and the Radial Scenario. There are a number of interconnectors that according to the ENTSO-E 10 year development plan [1] are planned for the North Sea. The routes for some of these interconnector circuits run very close to planned offshore wind farm sites and would therefore appear to offer the potential for co-development. Section 6 of the report sets out an analysis of likely design and associated capital cost of connecting these offshore wind farms into relevant interconnectors in a so called T-in arrangement. Section 6 also considers the likely technical issues associated with such a T-in arrangement. Section 7 considers the case for an interconnected or “meshed” offshore grid between Germany, Norway and The United Kingdom. These three countries were chosen initially as a test case to refine the methodology used to design the topology of the offshore grid before completing the design for Northern Europe as a whole and expanding the approach to the Mediterranean. The design of the offshore grid is an iterative process between Work Package 5, which produces the technical design and the capital cost of the assets, and the market modelling in Work Package 6, which provides a forecast on factors such as utilisation and constraints on the individual links up to 2030. Iterations between the two Work Packaes will result in revisions and enhancements to the preferred Offshore Grid design until the final topology has been established.


2 OFFSHOREGRID DESIGN ASSUMPTIONS

The three hundred and twenty six offshore generation projects that fall within the geographic sphere of this project, they range in capacity from as little as 5MW to a maximum of 2000MW and have connection route distances between 1km and 434km. The total offshore wind power in the study is 126GW in Northern Europe. Obviously to connect such a range of capacities over such a range of distances will require very different transmission technology solutions. Also due to the number of projects considered it will not be possible to individually design bespoke connection solutions for each project. Findings from Work Package 3 indicate that are there is also potentially 7.8GW of marine renewables consisting of wave and tidal energy generators that could be installed up to 2030, however only 3.5GW of these projects could be located at a specific site and have been included in the offshore grid design and costing. It is the purpose of this section to explain why certain transmission technologies have been selected for specific project connections and also define what design building blocks have been used to build up the Offshore Grid network from the individual project offshore substations through to the onshore connection points into the existing onshore transmission network. 2.1 Offshore Wind farm substations

The traditional voltage for interconnecting offshore wind turbines is 34.5kV however due to the power capacities accumulated in many of the offshore wind farms considered here and the distance from shore it is not possible for the power to be transmitted to the onshore grid at this voltage for most of the projects. Hence offshore substations will need to be established for many of the projects to accumulate the power from the array and step up the voltage to a level appropriate for transmission over distance. The amount of power that can be accumulated at one offshore substation, and hence the number of offshore substations required for each wind farm will be dictated by the power carrying capacity of the onward transmission medium, the power carrying capacity of the array cabling, the number of wind turbines, and the distance from the platform to the furthest wind turbine in the array (as using excessive lengths of 34.5kV cable to connect an array can lead to onerous power losses).

Figure 1 Location of offshore platforms for a specific project

(KEY: Green Dot – Wind Turbine Blue Dot –offshore substation)


Export cables then connect the offshore AC substation platforms either directly to the onshore grid or to HVDC converter platforms depending on the capacity and distance to shore. 2.1.1 Offshore Substation specification

Offshore platforms are required to house the substations which gather the array of cables from the wind turbines and step up the voltage for transmission to shore. Multiple platforms may be required depending on the capacity of the project and where the offshore transmission medium utilises High Voltage Direct Current (HVDC) a separate HVDC platform may be required. Platform topsides are supported on jackets (with anything from 3 to 8 legs) piled into the seabed. Monopiles can be used for smaller platforms and self installing floating platforms may be used in the future due to the shortage of installation vessels and cranes. In addition to housing transformers, cooling radiators and fans, switchgear, and the associated control panels, the platform will typically include emergency accommodation and life-saving equipment, a crane for maintenance lifts, a winch to hoist the subsea cables, backup diesel generator and fuel, helipad, communication systems and the means to support J-tubes which contain the subsea cables.

Figure 2 An Offshore Substation platform topside being shipped to site

Image courtesy of SLP Engineering

2.2 Available Transmission Technologies

2.2.1 High Voltage Alternating Current (HVAC) solutions

The advantage of using AC cables as a connection medium is obvious when the requirement is to link an offshore farm or farms which are generating at AC with an onshore network that is supplying AC, however the capabilities and limitations of AC cables are also well known, especially when connecting long distances. A characteristic of AC cable circuits is the charging current induced in the cable due to the capacitance between each phase conductor and earth. The need to allow for this charging current effectively reduces the ability of the cable to transfer useful power from one end to the other. The amount of charging current required increases as a function of cable length, with the result that beyond certain distances (which vary depending on the cable specification) all the cable capacity is consumed by the charging current and no useful power can be transferred to the receiving end. This effect can be seen in diagrammatic form in Figure 3 below.


HVAC and HVDC cable comparsion

0

50

100

150

200

250

300

350

400

0 100 200 300 400 500 600 700 800

Distance (KM)

Cap

acity

(MVA

)

132kV Onshore Compensation Only 132kV 50/50 Compensation 132kV 75/25 Compensation220kV Onshore Compensation Only 220kV 50/50 Compensation 220kV 75/25 Compensation350 MW 300kV HVDC

Figure 3 HVAC & HVDC cable power capacity comparison

Compensation refers to shunt reactors connected to the circuit at either end of the HVAC cable, located either 50:50 offshore and onshore or 75:25 onshore and offshore. HVDC cable capacity is only limited by resistive voltage drop, HVAC cable capacity is limited predominantly by charging current.


The charging current can be mitigated by connecting reactive compensation at regular intervals along the cable, however as most offshore wind farms require long sections of subsea cable, providing this interstitial reactive compensation would present an added technological and financial challenge, and hence it is more common to provide reactive compensation at the sending and receiving ends of the cable only. Figure 3 also shows the effect of adding such compensation to either end in different proportions to the effective transfer length of the cable. Providing such compensation is expensive, especially when required on an offshore platform, where any additional weight or space requirements impact directly on platform and jacket fabrication and installation costs. For these reasons AC subsea cables have only been considered as a possible connection technology in this study where the total cable route length is less than 80km. 2.2.2 HVAC Cable

AC cables come in many types, with variations possible on the metal used for the conductors (Copper or Aluminium), the type of insulation (oil mass impregnated (MI) paper or extruded cross linked polyethylene (XLPE)), the type and need for armouring, let alone the voltage and ampacity which dictate the power carrying capabilities of a cable and ultimately its cross sectional area. The choice of which type of cable to use is very much project specific and depends on a whole host of economic and environmental factors, such as capital cost, losses, and thermal resistivity of the medium in which the cable will be laid. However one of the key drivers when considering cable projects is the cost of installation. 2.2.3 Offshore HVAC Cable

This is particularly true in the offshore environment where long cable lengths are required at project locations which can be some distance from the cable manufacturing site. Hiring cable laying vessels is also an expensive proposition so trying to maximise the amount of time the vessel is laying cable and minimise the amount of time the vessel spends steaming to and from the manufacturing plant is key to minimizing project costs. The amount of cable that can be laid at one time is dictated by the weight and volume of cable that an individual vessel can carry. Obviously the heavier and/or fatter a cable is the less the vessel can carry and hence lay in one section and the more time will be spent in transit to and from the manufacturing plant. High voltage cables can be manufactured as single core (i.e. one conductor per cable carrying a single electrical phase) or three core (Figure 4, where a single cable has three conductors carrying all three electrical phases required for a single circuit).

Figure 4 Three core XLPE insulated subsea cable

Image courtesy of Prysmian


For a given power transfer rating an individual single core cable would obviously be lighter and thinner than its equivalent three core cable, however the cable laying vessel would need to transit along the cable route three times to lay the three single core cables necessary to complete one circuit, and hence in the majority of subsea applications it is three core cable that is specified, and therefore as a generalisation Senergy Econnect have considered only three core cables for the AC offshore sections of the proposed offshore grid designs. As mentioned above, Voltage is also a key variable in defining power transfer capability in cables. Currently three core cables are available and have been installed up to a nominal rating of 220kV. However the capacity and distance offshore of some of the projects within the North Sea and Baltic Sea zone would benefit from reduced capital costs were a three core cable with a higher voltage rating available, as this would enable single cable connections to be used. Again from a capital cost perspective it is more efficient to avoid the number of voltage transformations (and hence power transformers) required within a connection design, therefore specifying a cable transmission voltage that can connect directly to an onshore substation is ideal. For this reason, Senergy Econnect has confirmed with the cable manufacturers that production of a three core 400kV cable is feasible within the timescales covered by this study. 400kV has been chosen because of its use in the onshore transmission network around the North and Baltic Sea geographic zone. Cable ratings are determined on a per project basis due to the diverse range of environments found throughout Europe. Variables used to determine the cable ampacity are the temperature and the thermal resistivity of the ground or sea bed. It is assumed all cables are buried at a depth of 1m in the seabed or trenches on land. Cables derated based on sea bed thermal resistivity of North & Baltic Seas and 1.0m trenching / jetting. Hot spots in cables can be eliminated by using vented J-Tubes or bigger cross sectional areas at the landfall point. The design assumptions above mean that the offshore AC cable ‘building blocks’ used within the designs are as in Table 1 below.

Nominal Voltage

(kV) Cores Conductor Insulation Available

Pre 2020 C.s.a

(mm2)

Power Rating (MVA)

33 3 Copper XLPE YES 1200 52.1 132 3 Copper XLPE YES 1200 208.4 150 3 Copper XLPE YES 1200 236.9 220 3 Copper XLPE YES 1200 347.5 400 3 Copper XLPE NO 800 491.7

Table 1 Offshore AC cable design ‘largest building blocks’

2.2.4 Onshore HVAC Cable

Onshore the amount of cable that can be installed in one length is governed by the amount that can be transported by road on individual wooden cable drums. The clearance and weight restrictions imposed by road transport mean that onshore single core cable is favoured because it is easier to transport three smaller cable drums than one large cable drum. Hence for the purposes of this project, all onshore AC cables are assumed to be single core conductor as in Table 2 below.

Nominal Voltage

(kV) Cores Conductor Insulation Available

Pre 2020 C.s.a

(mm2)

Power Rating (MVA)

33 3 x Single Copper XLPE YES 2000 64.7 132 3 x Single Copper XLPE YES 2000 258.6 150 3 x Single Copper XLPE YES 2000 293.9 220 3 x Single Copper XLPE YES 2000 431.0 400 3 x Single Copper XLPE YES 2000 738.8

Table 2 Onshore AC cable design ‘largest building blocks’


The MVA rating shown in Table 1 and Table 2 is the maximum apparent power that may be transferred by the largest cross sectional area cable and is a combination of the real and reactive power. As discussed previously the reactive power increases as the cable length increases and reduces the amount of real power that may be transferred. All of the studies in this report use the cable length to determine how much real power can be transferred by a cable for a given cross sectional area so to determine the optimal cable to use. 2.2.5 High Voltage Direct Current (HVDC) Solutions

In DC transmission, a charging current only occurs during the instant of switching on or off (i.e. to charge and discharge the cable capacitance), and therefore has no effect on the continuous current rating (and hence power transfer capability) of the cable. In a HVDC system, electric power is taken from one point in a three-phase AC network, converted to DC in a converter station, transmitted to the receiving point by an overhead line or underground / subsea cable and then converted back to AC in another converter station and injected into the receiving AC network (Figure 5).

Figure 5 Overview of VSC HVDC transmission for offshore wind farms

Image courtesy of ABB

Traditionally HVDC transmission systems are used for transmission of bulk power over long distances because the technology becomes economically attractive compared with conventional AC lines as the relatively high fixed costs of the HVDC converter stations are outweighed by the reduced losses and reduced cable requirements. There are two technologies used in HVDC transmission: Current Source Converters (CSC) and Voltage Source Converters (VSC). CSCs are dependent on an external voltage source to drive the converter and feed its inherent reactive power demand. VSCs, on the other hand, function as independent voltage sources that can supply or absorb active and/or reactive power, therefore requiring no independent power source and making them suitable for offshore deployment. However the increased power losses arising from the semiconductor devices used within the VSC technology and the power ratings of the technology currently commercially available mean that at very high power transfer levels where there are strong AC networks connected at either end, for example on an interconnector then CSC technology becomes a viable option. 2.2.6 Current Source Converter HVDC Technology

CSC HVDC technology is older than VSC technology and is installed at many locations around the world. CSC technology requires a strong AC network to interface the HVDC link so is suited to connecting to strong points on existing AC networks. CSC systems are currently able to transfer the largest amounts of power for a given number of overhead lines or cables because the thyristor technology utilised is able to handle very high voltages and currents. ±500kV installations of CSC HVDC are in operation utilising overhead lines and ±800kV installations are under construction which can transfer up to 6000MW. Utilising cables, the highest voltage available is ±500kV, due to the insulation technology of the cable.


Although CSC HVDC systems are able to control very large amounts of real power flow they are unable to dynamically control the reactive power injected to or absorbed from the AC network, in contrast to a VSC HVDC converter station. Thus a CSC HVDC system requires reactive compensation to be connected to the AC side of the converter to compensate for the reactive power consumed by the converter and to provide the required reactive power to the AC grid. CSC HVDC converter stations require a strong AC network to interface with, because the thyristor technology utilised is “line commutated” (it can be switched on by a control signal but only ceases to conduct when the AC network changes polarity, which occurs 50 times a second in the EU). If connected to a weak network, commutation of the thyristors may not occur correctly and cause instability in the system. 2.2.7 Voltage Source Converter HVDC Technology

VSC HVDC is the latest development in the field of HVDC technology. The main difference with CSC technology is that VSC converter stations are able to form their own AC voltage waveform and act as a true voltage source. This gives total flexibility regarding the location of the converters in the AC system since the requirements for the short circuit capacity of the connected AC network is low, enabling VSC HVDC systems to be connected to very weak AC systems. Therefore VSC HVDC can connect remote electrical islands such as offshore generation and loads without the need for additional equipment. VSC HVDC technology has the capability to control both real and reactive power rapidly and independently of each other. The converter station can operate over a whole region of differing real and reactive power, unlike the CSC HVDC converter which can only provide discrete amounts of reactive power. This helps to keep the voltage and frequency of the associated AC system stable. The key technology that enables VSC HVDC converter stations to produce a voltage waveform is the high power Insulated Gate Bipolar Transistor (IGBT) which unlike the thyristors used in the CSC systems are self commutated, i.e. they can be switched on and off. This feature is used in different ways depending on the manufacturer of the equipment. Some manufacturers switch the IGBTs rapidly (up to 2000 times per second) to modulate a voltage waveform and others use a multilevel system where the IGBTs are switched between different voltage levels to modulate the voltage waveform. Both systems may be used in conjunction on the same DC grid. The ability of the VSC HVDC converter station to rapidly control the active and reactive power provides many benefits to the associated AC grid in the form of added stability, flexibility and dynamic response, but a significant advantage of VSC HVDC over CSC HVDC is the possibility of flexible multi-terminal operation. Multi-terminal operation allows the HVDC system to interface with the AC system at any number of points by connecting more converter stations to a DC grid. Although possible with CSC, control of the power flows in a multi terminal network is more onerous than with VSC and could lead to operational constrains if the power flow was required to be reversed frequently. At present the power handling capability of the largest available VSC HVDC converter module is 1200MW at ±320kV. Due to the number of MW that need to be connected and the distance of some of these projects from their onshore connection points, it is a key requirement of this study that the possibility of establishing offshore hubs where the output from a number of projects can be collected before being brought to shore is investigated. The advantage of a hub is that it reduces the amount of assets required on a per MW basis to transmit the power produced to the onshore connection point, and the cost of transmission per MW reduces as the power transfer capability of the hub increases. For this reason, Senergy Econnect have had discussions with HVDC converter manufacturers to confirm whether higher rated VSC converters could be manufactured within the timeframe considered in this study. There are three limits that will ultimately affect the capacity of these HVDC hubs, the first is the current carrying capability of the IGBT switching devices within the converters themselves, the second is the power transfer capability (i.e. the voltage and current rating) of the DC cable conductors, and the third is the level of instantaneous power infeed loss that any of the onshore transmission systems can cope with (this last point is covered in more detail in section 2.3). The result of these discussions is that the following HVDC converter capacities (Table 3) will be used within the OffshoreGrid design.

Type Voltage (kV) Configuration Available Pre 2020 Power range (MW) VSC +/-150 Symmetrical monopole YES Up to 500 VSC +/-320 Symmetrical monopole YES Up to 1200 VSC +/-500 Symmetrical monopole /Bipole NO Up to 2000 CSC +/-250 Bipole YES Up to 1000 CSC +/-500 Bipole YES Up to 2000 VSC +/-150 Symmetrical monopole YES Up to 500

Table 3 HVDC Converter design ‘building blocks’


Figure 6 HVDC VSC Synchronous Monopole configuration


Figure 7 HVDC Dual Converter pair redundant Bipole configuration


2.2.8 HVDC Return Path

HVDC systems operating in synchronous monopole or bipole configurations use two cables operating at opposite polarity with the current circulating around both conductors. HVDC systems operating as asynchronous monopole


systems have one conductor at the live potential and one operating at earth potential. Therefore the return path for the current may use the earth, sea or a low voltage cable to carry the return current between converter stations. The difference between bipolar and monopolar is bipolar systems have 2 converters in series at each end of the HVDC link. Normally both converters are in service, however if necessary only one converter at each end could operate to transfer half power through the link. The various configurations have implications in the event of pole failures, either due to a cable fault or a converter station or transformer fault. VSC Symmetrical monopoles – no earth return, all capacity lost in event of cable or converter fault. VSC Asymmetrical monopole – earth return, all capacity lost in event of cable or converter fault. VSC Bipole – When single converter is lost the link can operate at half capacity, the existing pole cable may then be used as the earth return path. If a pole cable fault is experienced then an earth return could be used to operate at half rated capacity. The earth return may use either earth electrodes and the sea or a dedicated earth return cable if environmental reasons do not permit. Bipolar systems are introduce redundancy but are more expensive than monopolar systems. 2.2.9 HVDC Cables

Mass Impregnated cables have been the traditional medium for transmission in DC systems over the last century. As the name suggests the conductors are insulated with special paper impregnated with a high viscosity compound. They can be used for voltages up to 500kV. More recently, as the interest in Voltage Source Converter technology has grown, DC cables have also been developed that use on extruded cross linked poly-ethylene as the insulation medium for the conductors. These cables are easier to manufacture and correspondingly cheaper than their MI equivalent, however currently available commercially at voltages up to 320kV which limits possible power flow. Currently XLPE cables have only been developed to work with VSCs but mass impregnated cables can be used with both CSC and VSC systems.

Figure 8 Mass Impregnated 500kV DC cable (left), XLPE 150kV DC cable (right)

Image courtesy of Prysmian Powerlink

In order to reach the levels of power transfer required for the 2020 and 2030 OffshoreGrid designs, cables that can operate at a higher voltage would be required. Again as a result of conversations with the cable manufacturers the following DC cables in Table 4 have been specified within the design.


Nominal

Voltage (kV) Conductor Insulation Available pre 2020 C.s.a (mm2) Max Sending

Power (MVA) 150 Copper XLPE YES 2500 600 320 Copper XLPE YES 2500 1280 500 Copper XLPE NO 2500 2000 500 Copper MI YES 3000 2000

Table 4 Offshore DC cable design ‘building blocks’

2.2.10 Super Conductors

Super conductors are able to transfer large amounts of power using low voltages without the high electrical losses that are normally experienced using traditional conductors. However to maintain their super conducting state they must be kept very cold, therefore the superconducting cables require cooling stations to be located approximately every 2km along the length of the cable. This is not practical for offshore applications as the cost of the cooling stations would outweigh any advantage gained from the super conducting cables. For this reason super conductors have not been considered as a transmission technology for the Offshore Grid. 2.2.11 Gas Insulated Transmission Lines

Gas Insulated Lines (GIL) are a 3 phase AC transmission technology available up to 400kV and 3000MW. They are able to transfer large amounts of power over greater distances than AC cables because they use SF6 gas as the insulating medium between the live conductors and earth instead of XLPE. The result is the GIL has a lower capacitance meaning longer distances may be connected before the real power transfer capacity becomes limited by the charging current associated with AC transmission. GIL has been installed onshore in transmission systems and is directly buried in the ground, for subsea applications the GIL must be installed in a pipeline to provide physical protection. GIL has been considered in the OffshoreGrid design but due to the high costs of building and installing the GIL in subsea pipelines it has not been used for any of the designs, because the alternative HVDC is currently cheaper. 2.2.12 Switchgear

HVAC Gas Insulated Switchgear

An offshore network using HVDC technology will still require AC equipment at the nodal locations where the HVDC system interfaces with the existing onshore AC grid. In addition, offshore renewable generation utilises generators with an AC output, therefore AC switchgear is required to provide protection, switching and monitoring of voltage and current on the AC side of the network. Gas Insulated Switchgear (GIS) uses SF6 gas instead of air to provide isolation between the high voltages and the components of the system at earth potential. SF6 gas has significantly greater dielectric properties than air, allowing much smaller distances between live conductors and earth to be achieved. GIS switchgear is better suited to offshore applications than air insulated switchgear (AIS) types due to the low space requirement offshore. In addition, it is completely immune to any pollution or contaminants (e.g. salt air & spray) in the surrounding environment due to its sealed enclosure. This enclosure also ensures maximum safety to the operational personnel. In addition GIS can be used on land where land space is limited or expensive. Figure 9 shows GIS equipment, in summary GIS has the following advantages compared to that of AIS:

• Compact design with less space requirements • Low sensitivity to pollution (e.g. salt, sand or even large amounts of snow) • Low operation & maintenance requirements • Overall lifetime costs can be lower, despite higher capital cost of apparatus, due to reduced land

requirements, and lower maintenance • Planning permissions can be assisted by the compact nature of equipment, and the ease with which GIS

can be accommodated within buildings and structures


Figure 9 Gas insulated switchgear


HVAC Air Insulated Switchgear

Air insulated switchgear (AIS) needs large separation distances between phase conductors and earth to avoid flashover and leakage currents. AIS is less expensive than the GIS equivalent, but is however much larger in size and hence it is suited to land based operations where space requirements may be less of an issue. Figure 10 shows AIS equipment. Outdoor switchgear, using open busbar connection arrangements is available up to 800kV. All AIS types are exposed to the environment and vulnerable to airborne pollution and spray. This can result in reduced reliability compared with GIS types.


Figure 10 Air insulated switchgear


HVDC Switchgear

HVDC switchgear with the exception of circuit breakers is similar to existing AC switchgear and may use either AIS or GIS design. AC circuit breakers rely on the voltage crossing zero volts to break the fault current flowing through them. DC circuit breakers require an additional mechanism to break the current because the voltage does not alternate through zero volts. DC circuit breakers are currently not commercially available but discussions with manufacturers have revealed that a DC circuit breaker will be introduced in the near future. The methodology used in the offshore grid designs has been to use DC fault isolation equipment such as DC circuit breakers to prevent any power infeed loss to onshore AC transmission systems exceeding the amount of frequency control reserve held by the onshore system. If an electrical fault occurred on the offshore grid and the interruption to power being fed into an onshore system was higher than the amount of reserve held then the frequency of the onshore grid may start to fall due to the miss match between generation and load. This may trigger tripping of loads and cause blackouts for customers on the onshore network. DC circuit breakers are able to segregate the DC grid so that a fault on a cable or converter does not interrupt all of the generation and power transfers so the remainder of the un-faulted grid is able to operate without any interruption. Therefore this methodology would require circuit breakers if the offshore grid had multiple connections to the mainland Europe transmission system, which is interconnected and shares spinning reserve across countries. However it may not if the offshore grid had two connections, one to the NORDEL system operating in Scandinavia and the other to the GB system. This is because each separate AC network will hold enough reserve to cater for a loss of an offshore grid link. 2.3 System Operator Requirements

The technical integration requirements from the onshore transmission system operators (TSO) are fundamental to the offshore grid design. One of the key aspects of these requirements that directly affects the offshore grid design even at this initial stage is discussed below. 2.3.1 Frequency Control Reserve

The frequency control reserve value is effectively the level of instant response and reserve that individual or collective Transmission System Operators hold ready to replace energy lost through a fault, either through the failure


of a circuit or circuits or the sudden shutdown of an entire power station. As demand and generation within the system must be exactly balanced, the sudden loss of generation (terrmed ‘power infeed loss’) would cause the frequency of the system to drop (as demand would then exceed generation) and ultimately if uncorrected lead to system blackout. For this reason TSO’s plan and operate their systems to ensure that they hold enough reserve and response (effectively spare MW that can be supplied instantly or in short periods of time) to prevent system blackout in the event of a credible fault. The reason this impacts on the design of the OffshoreGrid is that the amount of power infeed that can be lost for a fault on one element of the offshore network will dictate the power transfer that can be assigned to that element and ultimately shape the design of the OffshoreGrid itself. The level of power infeed loss that individual TSO’s can handle is ultimately an economic decision (as the TSO’s have to pay for these ‘spare MW’s to be available in the timescales required) however it is normally based on the largest credible infeed loss that could occur on that TSO’s system. For example on the GB system, the largest infeed loss risk that National Grid (the GB System Operator) currently hold response for is 1320MW which is based on the sudden loss of the Nuclear Reactor at Sizewell B power station. However there are plans to increase this to 1800MW to cover the next generation of planned nuclear power stations [2]. The OffshoreGrid proposed in this study has therefore been designed to not exceed the Frequency Control Reserve levels for each country as defined in table below. These values were based on information provided in the UCTE Load-Frequency Control and Performance document 2009 [3] and Nordel System Operation Agreement (2008) [4].

Country Frequency Control Reserve (MW)

Belgium 3000 Denmark 168* Estonia TBC Finland 251* France 3000

Germany 3000 Ireland 600 Latvia TBC

Lithuania TBC Netherlands 3000

Norway 348* Poland 3000 Russia TBC

Sweden 394* United Kingdom 1800

Table 5 European Frequency Control Reserve levels

* Note the Nordel countries of Sweden, Norway, Finland and Denmark combine to provide a primary Frequency response holding of 1160MW against an infeed loss risk of 1360MW.


3 OFFSHOREGRID DESIGN METHODOLOGY

It is the purpose of this section to explain the methodology that was used to produce the Offshore Grid topologies using the building blocks defined in Section 2. 3.1 Defining the OffshoreGrid

To understand this methodology it is first necessary to define the extent of what is termed the ‘OffshoreGrid’. Senergy Econnect would contend that this term relates to the bulk transmission of power from offshore generating stations to onshore connection points and from one country to another via offshore interconnectors. This would mean that that the OffshoreGrid would start at the offshore substation platform where an individual power station’s output is collected, and would include the AC or DC transmission medium for transmitting this power to shore directly or onto a larger ‘hub’ offshore collection point and then through a further AC or DC transmission medium to the onshore connection point. It would also include whatever equipment was required to connect these offshore transmission mediums to the existing onshore electrical transmission network. Therefore it would not include any of the internal array equipment necessary to connect individual generating units, nor will it account for any reinforcements required to the existing onshore transmission network as a result of the connection of the OffshoreGrid networks. 3.2 Establishing the offshore project capacities and locations

Transmission capacity for 90% of the installed offshore project capacity has been designed and costed. Due to the high capital cost of offshore transmission assets they require high utilisation and this may be achieved using a lower export capacity. 90% has been calculated as an optimal based on offshore wind capacity factors and availability of offshore turbines. The full analysis can be found in [5]. Offshore generation locations and connection points have been produced in WP4 and then plotted in GIS to establish their locations relative to the onshore connection points. Offshore GIS layers were overlaid in the software consisting of existing cables and pipelines, mineral extraction areas, areas of special scientific interest and nature reserves. 3.3 Assessing On and Offshore Cable Routes

Offshore, the most direct cable routes were established and plotted in a Graphical Information System database from the offshore substation locations to the proposed landfall points. These direct routes were then amended to avoid as far as possible any subsea obstacles, such as mineral extraction areas or other wind farms, or excessive changes in the depth of the seabed. Where the crossing of subsea obstacles such as gas and oil pipelines was unavoidable, the cost of these crossings (using concrete mattresses and rock dumping etc) has been included in the overall costings. Onshore, as it is outside the scope of this study to establish optimized cable routes for 300+ projects, as an approximation a straight line was drawn in the Graphical Information Database from the landfall point to the proposed connection point and a 10% contingency added to allow for likely variation. The combined length of these on and offshore cable routes were then used to determine the total cable costs for each design. 3.4 Land Fall Requirements

All of the designs in the offshore grid project utilise subsea cables that must be brought ashore at a suitable landfall point. To take into account the costs associated with transferring the cable from the subsea trenches to onshore trenches a cost for directional drilling and transition works such as winching the cables ashore etc has been applied to each cable brought ashore at the landfall point. Note the landfall sites themselves have not been specifically chosen, they are generally as close to the straight line route between the project and its connection point as possible except where information on specific restrictions has been obtained such as for landfall on the German North Sea coast.


3.5 Asset Redundancy

3.5.1 Number of Transformers

The number of AC transformers has been chosen to be 2 per offshore AC platform to step up the array voltage to the export voltage for connection to shore or DC platform. The choice of 2 transformers is based on the analysis by Djapic and Strabac in [6]. The report uses a cost benefit analysis based methodology considering the capital cost of equipment and the cost of constraint due to failures and power losses over the lifetime of the transformer to determine the optimal number and size to use. The cost of constraint was calculated using historical figures for failure rates and repair times to determine duration of an outage and calculated the cost of lost revenue from the generation based on typical wind profiles for different numbers of transformers. The result was 2 transformers per platform were recommended for the majority of cases. 3.5.2 Number of AC Circuits

A similar analysis used for the transformers was used to determine the optimal number of cables to use per AC platform. No benefit was found in the study for installing more than one cable per platform unless the platform capacity exceeds the rating of the available cable technology. The high capital cost of cables and the relatively low failure rate meant it would be less economic over the lifetime of a project to install multiple cables for redundancy purposes over a single cable. 3.5.3 DC Monopole or Bipole Design

HVDC links may be use monopolar or bipolar designs. In a monopole HVDC link the failure of the pole (e.g. due to a cable or converter fault) will lead to the power transfer being lost. Bipolar systems introduce redundancy because they have 2 converter stations at either end of the link. In the event of a converter station fault the link is able to operate at half rated power until the fault is repaired. Also if a cable develops a fault the converter may operate at half rated power using an earth return or a low voltage metallic return path. A key aspect of this operation with regard to security of supply for onshore transmission systems is the ability of a bipolar HVDC converter station to instantaneously switch to half power in the event of fault. Senergy Econnect has had discussions with suppliers of HVDC systems and concluded that the ability to switch to half rated power is technically possible. Bipolar designs have been used where the resulting infeed loss to the onshore transmission system would exceed Frequency Control Reserve level held by the system. 3.6 Cost Inclusions and Exclusions

The costing of the offshore grid designs set out in Sections 4 to 7 of this report examines capital cost of design, procurement and construction of the offshore grid in light of market conditions and prices current at the time of writing. These costs ignore ongoing operation and maintenance and also do not take into account wider economic and fiscal matters such as inflation, currency exchange rates and cost of finance. A summary of electrical and civil plant included in and excluded from the costings are summarised in Table 6 below. In order to provide as accurate a capital cost model as possible, a number of high voltage power equipment manufacturers and installers were consulted in order to establish prices for equipment required to realize the offshore connection designs described in this report. Information was very helpfully supplied by ABB, Areva T&D, Nexans, Prysmian and Siemens. Due to the impact on cost of the actual installation conditions specific to the site, the fluctuations in price of raw materials and limitations of manufacturing resource, the costs of equipment quoted by the manufacturers can only ever be generic at this high level stage, and hence the cost estimates provided within this report are only indicative. The equipment costs provided by the manufacturers were then compared to equipment cost information in the public domain, such as that set out in the SEDG report [6]. Average prices were then calculated for each equipment element and then used to cost the connection designs proposed. The connection design cost inclusions and exclusions are listed in Table 6 below and a diagram showing a typical offshore hub design is shown in Figure 11.


OffshoreGrid Design

Cost Inclusions

OffshoreGrid Design

Cost Exclusions

Onshore Double busbar GIS transformer / feeder bays HVDC converter station onshore Onshore reactive compensation Onshore 3 x single core AC cable supply & installation Onshore DC bipole supply & installation Transition pit civil works & cable winching Offshore three core subsea AC cable supply & installation (transmission to shore & inter-platform) Offshore DC bipole supply & installation Offshore platform provision and installation Offshore DC converter Offshore platform GIS transformer bays Offshore reactive compensation Earthing transformers Subsea Oil/Gas pipeline crossings

33kV offshore switchboards Wind farm 33kV array cabling Offshore reactive compensation for array cabling Wind Turbines and installation Onshore Transmission Network Reinforcement

Table 6 Offshore connection design cost inclusions

The cable costs include material, transportation from the factory, laying and burial with trenching of the subsea cable with water jetting down to a maximum of 1m and normal excavation for the land cable down to a maximum of 1m. The amount of reactive power compensation included at both the offshore platform and onshore connection point has been estimated and costed for solutions using AC cables. The reactive power compensation applied is solely to compensate for the capacitive charging current of the inter wind farm and transmission cables and to maintain a 0.95 to 0.95 power factor at the receiving end at the onshore connection point, but does not allow for any compensation of the internal wind farm array cabling. 3.7 Offshore substation/hub to shore design

The wind farm or hub to shore design process takes the total export capacity of the wind farm or all the offshore projects to be clustered to define a transmission/hub entry capacity. For each transmission technology the following parameters are then calculated:

• Capacity of one circuit using cables with different cross sectional areas and operating at different voltages at hub/platform substation to shore distance and thermal conditions

• Number of circuits required given capacity and infeed loss criteria • Amount of reactive compensation required • Cable full load losses – If the total cable losses (%) are in excess of the loss limit (%) then the technology is

marked as not suitable for use. • Number of DC converters required • Number of transformers • Switchgear & auxiliaries • Cost per connection for each technology (=cables + converters + transformers + switchgear)

The cheapest technology is then selected and used providing it is technically suitable. 3.8 Hub to Offshore Project design

A number of variables relating to the hub to offshore project connection are fixed following the hub selection process, these being:

• If the hub to shore technology is AC, then the AC hub to shore voltage equals the hub to offshore project voltage to avoid the need for additional transformers on the offshore platform.


For each cable technology the following parameters are calculated: • Capacity of one circuit using cables with different cross sectional areas and operating at different voltages

at hub to offshore project distance and thermal conditions • Number of circuits required • Amount of reactive compensation required • Cable full load losses – If the total cable losses (%) are in excess of the loss limit (%) then the technology is

marked as not suitable for use • Number of DC converters required • Number of transformers • Switchgear + auxiliaries • Cost per connection for each technology (=cables + converters + transformers + switchgear)

AC or DC (if applicable) is selected depending on the cheapest option. Note the same connection voltage will be used for all of the hub to offshore project connections within a cluster. Limitations: If the total capacity of projects to be clustered exceeds the maximum capacity of an available technology (e.g. 2GW HVDC Link) then multiples there of a smaller rating will be chosen. In reality this will not be an efficient solution. Each project number is used to lookup capacity based on the project’s export capacity (90% of installed capacity) and the total export capacity is determined for the cluster. 3.9 Onshore Grid Integration

The offshore grid design is limited to the offshore power transmission assets up to the connection points identified in Work Package 4. No optimisation of the onshore grid network will be carried out as this is subject to other studies. Note that in some of the Offshore Grid designs proposed in this report, the offshore transmission system extends to more distant connection points onshore than those closest to the coast, particularly in Germany. This is because the designs proposed balance the need for offshore and likely onshore reinforcement in order to achieve the optimal solution. Onshore substation designs may be either HVAC or HVDC depending on the capacity and distance of the offshore transmission assets. HVAC designs include transformers if the onshore and offshore voltages are different as well as the associated switchgear. Reactive compensation equipment and associated switchgear has also been included in the design to compensate for the charging current of the HVAC cable system and to support the voltage of the onshore existing transmission network by providing reactive power in the range 0.95 lagging to 0.95 leading power factor. HVDC designs include the HVDC converters, converter transformers, associated HVAC switchgear and land costs. For both the AC and DC substations GIS switchgear has been used and costed. In practice GIS switchgear is more expensive than air insulated equipment and usually required for substations less than 5km from the shore, where the moist air would accelerate the corrosion of air insulated equipment. It is also required where the land available at the onshore substation is at a premium or where planning requirements prevent the construction of a large air insulated substation. The decision on the most appropriate type of switchgear to use would require detailed analysis of each connection point and is outside the scope of this study.


Figure 11 Example HVDC design including AC platforms


4 RADIAL SCENARIO 2030

4.1 Radial Scenario 2030

The Radial Scenario is designed to represent the eventual scenario should the practice to date regarding offshore wind farm connection be continued, i.e. it assumes that each individual developer seeks connection solely for there own offshore generator and hence provides a design and cost for connecting each individual offshore project identified in WP4 for 2030 directly to an onshore connection point at an appropriate voltage and using an appropriate technology for the power transfer required and distance covered. Only interconnectors included in the ENTSO-E 10 Year Development Plan [1] have been included in the base case design. Where a particular project is being built in phases over a number of years, and where a certain technology/capacity would be most economically efficient for the eventual total project capacity then this solution has been specified, recognizing that there is a potential risk of overspend if the subsequent phases of the project do not get commissioned. The aim of the Radial Scenario is to represent the benchmark against which all further designs can be compared, as in reality some developers are already considering sharing connection assets. 4.2 Results

Table 7 below shows the key results of the Radial Scenario analysis with the German Bight area design shown in Figure 12.

Item Total

Total Connected Capacity 129.3GW Total Cost €83.201bn Total Cost/MW for generation €643k/MW

Table 7 Radial Scenario key results

Case AC Circuit Length (km)

DC Circuit Length (km)

Radial Scenario 12,494 24,530

Table 8 Radial Scenario Cable Summary


Figure 12 German Bight Radial Scenario


5 2030 HUBS BASE CASE

The Hub Base Case is the first step towards a true offshore grid in that it recognizes that in many cases it will be more economic to group the relatively small project capacities offshore to transmit the combined power through a bulk transmission medium. This is especially true where projects are a significant distance from their intended onshore connection point, the German North Sea projects being a prime example. Obviously there are limitations as to the number and capacity of projects that can be grouped together effectively, one limitation is the power carrying capability of the bulk transmission medium used, if you like the size of the pipe back to the onshore connection point, but the main consideration is economic, i.e. when is it cost effective to group two or more projects together and share the cost of a bulk transmission medium rather than connect each project individually. This is primarily determined by distance, both between the projects and their prospective offshore ‘hub point’, but also the distance of the prospective offshore hub point from the onshore connection point. The tool developed by Senergy Econnect and described in Section 5.1 below was used to help determine which of the offshore projects could be economically grouped together. 5.1 Economic Hub Assessment Tool

Project

Connection point

X

Y

Z

Hub

Figure 13 Representation of Hub Assessment Tool reference points

This tool was designed to verify that the hubs proposed within this report are economically efficient, as such the tool considers the worst case scenario (i.e. likely least cost effective project to group) where the project in consideration (identified by the green dot in Figure 13) is between the proposed hub location (identified by the orange dot) and the onshore connection point (identified by the blue dot). Basically a hub connection is deemed cost effective for a project where the cost of the connection to the hub added to the project share of the cost of the hub to connection point assets is less than the cost of the direct connection to shore or in more formulaic terms: -

Hub connection economic if - % X(€) + Y(€)<Z(€) As the cost of the X, Y and Z asset elements will be determined by the distance and therefore technology involved, the tool was set up to use certain technologies for certain ranges of


distance/power transfer capability combinations from a minimum distance of 30km to a maximum distance of 250km and transfer capabilities from 200MVA using AC 150kV 3 core cable to a maximum of 2000MVA using HVDC VSC technology. The algorithm was then set to determine economic hub connection distances (Y) for projects ranging in size from 200MW to 1000MW to hubs ranging in capacity from 350MW to a maximum of 2000MW at varying (distance) values of X and Z. This tool was only used to verify the hub grouping designs as it only determines what the minimum economic connection radius from a hub is for a particular project capacity, as should the project be located beyond the hub (i.e. further away from the onshore connection point) then the economic connection distance would be greater. Where this was the case for a particular project/hub combination in the designs presented here, then a manual cost comparison exercise was undertaken. The hub design for the German Bight is shown in Figure 17 below. 5.2 Results

The costs for the Offshore Wind farm groups/hubs identified within the North and Baltic Seas are shown in Table 9 below with their equivalent Radial Scenario costing shown for comparison. Note not all the offshore projects have been included in the groups below as due to either the project capacity, connection distance, distance between projects, or predicted commissioning date (compared to its near neighbours), it was uneconomic to group some projects into hubs. For comparison purposes these projects would retain their base case connection designs and hence costs.

Country Radial

Scenario Cost (€m)

Power Export (MW)

No of Projects in

Hubs

Hub Costs (€m) Total (€m)

Difference to Radial

Scenario (€m)

% of Radial

Scenario

Belgium € 1,554 3,794 5 € 744 € 1,556 -€ 3 100.2 Denmark € 2,352 3,799 4 € 534 € 2,282 € 70 97.0 Estonia € 826 1,600 0 € 0 € 826 € 0 100.0 Finland € 1,726 3,190 8 € 1,345 € 1,454 € 272 84.2 France € 1,862 4,914 0 € 0 € 1,862 € 0 100.0 Germany € 28,069 26,553 59 € 14,449 € 18,650 € 9,419 66.4 UK € 21,341 41,646 9 € 7,904 € 19,483 € 1,858 91.3 Ireland € 1,561 3,780 0 € 0 € 1,561 € 0 100.0 Latvia € 269 900 0 € 0 € 269 € 0 100.0 Lithuania € 430 1,000 0 € 0 € 430 € 0 100.0 Netherlands € 8,366 12,122 16 € 3,915 € 6,518 € 1,849 77.9 Norway € 5,205 9,667 0 € 0 € 5,205 € 0 100.0 Poland € 2,993 5,300 8 € 1,370 € 2,670 € 323 89.2 Russia € 324 500 0 € 0 € 324 € 0 100.0 Sweden € 6,323 10,522 5 € 1,368 € 6,004 € 318 95.0 Total € 83,201 129,287 114 € 31,628 € 69,096 € 14,105 83.0

Table 9 2030 Hubs and Radial Comparison

Case AC Circuit Length (km)

DC Circuit Length (km)

Radial Scenario 12,494 24,530 Base Case with Hubs 10,370 12,566

Table 10 Circuit Length Summary


€ 0

€ 10,000

€ 20,000

€ 30,000

€ 40,000

€ 50,000

€ 60,000

€ 70,000

€ 80,000

€ 90,000

Radial Scenario Hub Design

Mill

ions

Hubs

Radial Scenario

Figure 14 Comparison of Radial Scenario and Hubs costs

Circuit Length Comparison

0.00

5,000.00

10,000.00

15,000.00

20,000.00

25,000.00

30,000.00

AC DC

Leng

th (k

m)

Radial CaseBase Case with Hubs

Figure 15 Cable Length Comparison Radial to Hubs


Comparison

€ 0

€ 5,000

€ 10,000

€ 15,000

€ 20,000

€ 25,000

€ 30,000

Belgium

Denmark

Estonia

Finlan

d

France

German

yUnit

ed King

dom

Irelan

d

Latvi

a

Lithu

ania

Netherl

ands

Norway

Poland

Russia

Sweden

Mill

ions

Country

CA

PEX Radial Scenario Cost

Hubs

Figure 16 Comparison of Radial and Hub costs by country


Figure 17 German Bight Hub Design


6 INTERCONNECTOR T-IN EXAMPLE

There are a number of interconnectors that according to the ENTSO-E 10 year development plans [1] are planned for the North Sea. The route for some of these interconnector circuits run very close to planned offshore wind farm sites, and hence an analysis has been undertaken of the capital cost of connecting these offshore wind farms into the interconnector in a so called T-in arrangement. As the key evaluation criteria when assessing the efficiency of connecting offshore wind farms into interconnector circuits is the level of constraint both on the output of the wind farm and/or the level of arbitrage possible on the interconnector itself, Senergy Econnect have designed and costed four different scenarios with different levels of power transfer capability for each Interconnector T-in example, to allow the level of constraint (and it’s implications) to be assessed for each design in WP6. There are several combinations of the scenarios with the economic modelling in WP6 and these are shown in Table 12. Two planned interconnectors were chosen to be analysed based on their proximity to wind farm sites within the Norwegian, German, United Kingdom case study area. These were the planned BritNor interconnector between Norway and the UK and the planned Nordlink interconnector between Norway and Germany. The BritNor and Nordlink projects are both planned as point to point connections over large distances. The distance between the converter stations requires a high voltage submarine cable system to be used in order to minimise the transmission losses. For this reason 500kV bipole mass impregnated cables have been selected in both designs. The converter technology may use either voltage source or current source converters with the mass impregnated cable system however only CSC is commercially available now at voltages of 500kV and hence has been chosen as the converter technology for both links. The wind farm (or wind farm group in the Nordlink analysis) were then connected to this interconnector via a +/-500kV Voltage Source Converter. It is possible to use different ratings of the cables and converters on different segments of the T-in arrangement. This is because HVDC is able to control the power flow to ensure circuits are not overloaded. Connecting sections of cable together with different cross sectional areas is also possible and has been done on projects to date where cables of different conductor materials and cross sectional areas have been jointed. Senergy Econnect has discussed T joints with cable manufacturers and some acknowledged they foresee their need in the future and manufacturing them would not be a significant challenge. The choice of which Offshore wind farm projects to connect was determined by their proximity to the interconnector route in question (which has been plotted using GIS) and the distance to their proposed onshore connection points in the 2030 base case hubs design. 6.1 Limitations of T-in CSC Design

The CSC technology proposed in the BritNor and NordLink designs is able to transfer power in both directions, however to reverse the power flow requires the link to be shutdown and the pole polarities swapped over. This is because the in current source converters the current flows in the same direction at all times, so to swap the power flow the voltage polarity must be reversed. This introduces additional constraint on a wind farm connected to the link because it would require the windfarm to shutdown while the power flow is reversed regardless of whether the windfarm is generating or not. Alternatively the power flow direction on the interconnector could be maintained until the wind stops blowing and the windfarm is not generating before the reversal is implemented. In either scenario there are constraints around how the system could operate. In order to reverse the power flow the power must be ramped down at rates which are acceptable to the onshore networks. This may be around 100MW / minute down to the lowest power transfer capability of the CSC link which is typically 10% of the rated power before the cable is de-energised and the offshore VSC converter will disconnect the offshore windfarm. It is possible for the converters to reverse the pole voltages in less than 1 second. In emergencies this could be done and then the power ramped up in the opposite direction. However there is normally a cable deionisation duration applied before the cable voltage is reversed. This is approximately 5 minutes for mass impregnated cables but varies by the design of the cable. When the deionisation is


complete the cable can be re-energised and the power flow ramped up in the opposite direction, at the same time the offshore VSC converter could reenergise the offshore windfarm. Wind turbines may take several minutes to resume generation after energisation resulting in a total outage of between 5 and 10 minutes (Figure 18). An alternative solution would be to use voltage source converters at either end of the link as well as for the offshore windfarm, should converters be available at the required voltage and power rating. The system would then not require any shutdowns other than for planned maintenance because voltage source converters are able to operate down though zero MW power transfer without the need to swap the pole voltages.

Figure 18 CSC Pole Reversal Time

6.2 BritNor – Dogger Bank A Interconnector T-in

The design for the BritNor Interconnector in the ENTSO-E 10year development plan is for a 1400MVA rated HVDC ±500kV bipole using Current Source Converters between Triton Knoll North and Kvilldal. The Dogger Bank A wind farm has been determined by WP4 to have a capacity of 1000MW. Hence the four scenarios/designs for which capital costs have been determined are given in Table 11 below with reference to Figure 19 and Figure 20.

Scenario Bipole

Section A (MVA)

Bipole Section B

(MVA)

Windfarm Connection

Potential NO – GB Arbitrage

Potential Windfarm

Output 1 1400 1400 Direct to GB Unconstrained Unconstrained 2 1400 1400 Interconnector Constrained Constrained 3 2000 1400 Interconnector Constrained Constrained 4 2000 2000 Interconnector Constrained Constrained

Table 11 BritNor – Dogger Bank A Interconnector T-in configurations

A number of cases have been studied using a combination of the above scenarios for further analysis in Work Packages 6 and 8. These are shown in Table 12.

500

250

0

Pow

er (M

W)

t ramp down t ramp up

Pole Reversal Time

Time for Windfarm to Restart

Windfarm Power Output

Interconnector Power

Transfer


Norway BritNor I/C CSC Norway station +/- 500kV DC Bipole (Section B) Dogger Bank A (1000MW) OWF VSC station +/- 500kV DC Bipole (Section A) BritNor I/C CSC GB station GB

Figure 19 BritNor – Dogger Bank A OWF Interconnector T-in example


Figure 20 BritNor – Dogger Bank A OWF and Nordlink – Dan Tysk OWF Interconnector T-in

examples


Illustration Case

Case 5:

Base Case 2030

BritNor & Dogger Bank A

BritNor Interconnector and Dogger Bank A 1000MW wind farm connection costs in isolation for comparison

Case 6:

BritNor/Dogger Bank A T connection – planned capacity

To assess capital cost savings against arbitrage constraints

BritNor 1400MW

BritNor 1400MW

Dogger Bank A T


Illustration Case

Case 7:

BritNor/Dogger Bank A T connection – 2000MW capacity to UK only

To assess capital cost savings against reduced arbitrage constraints

Case 8:

BritNor/Dogger Bank A T connection – 2000MW capacity to UK and NO


BritNor 1400MW

BritNor 2000MW

BritNor 2000MW

BritNor 2000MW

Dogger Bank A T

Dogger Bank A T


Illustration Case

Case 9:

Case 10:

BritNor/500MW OWF T connection – planned capacity


BritNor 1400MW

BritNor 1400MW

Dogger Bank A T (500MW)

Dogger Bank A 500MW Radial

BritNor 1400MW


Illustration Case

Case 11:

BritNor/500MW OWF T connection – 2000MW capacity to UK only


Case 12:

BritNor/500MW OWF T connection – 2000MW capacity to UK and NO


BritNor 1400MW

BritNor 2000MW



BritNor 2000MW

BritNor 2000MW




Illustration Case

Case 13:

BritNor/Dogger Bank A T connection at planned capacity plus additional interconnector

To assess capital cost against reduced arbitrage constraints

Case 14:

BritNor/Dogger Bank A T connection – 2000MW capacity to UK only plus additional interconnector


BritNor 1400MW

GB – NO 900MW

BritNor NO 1400MW

GB – NO 900MW

BritNor GB 2000MW

Dogger Bank A T

Dogger Bank A T


Illustration Case

Case 15:

BritNor/Dogger Bank A T connection – 2000MW capacity to UK and NO plus additional interconnector


Case 16:

Base Case 2030

With Dogger Bank A but BritNor removed

Interconnector (excluding BritNor) and Dogger Bank A 1000MW wind farm connection costs in isolation for comparison

Table 12 T-in cases studied for Dogger Bank A – BritNor

BritNor NO 1400MW

GB – NO 900MW

BritNor GB 2000MW

Dogger Bank A T


6.2.1 BritNor – Dogger Bank A Interconnector T-in Capital Costs

Scenario Section A (MW)

Section B (MW)

Wind farm Connection Constraint I/C Cost

(€m)

WF connection cost (€m)

Cost (€m)

1 1400 1400 Base Case - Direct to GB Unconstrained €1,446 €587 € 2,033

2 1400 1400 T-in Constrained €1,447 €296 €1,743 3 2000 1400 T-in Constrained €1,656 €296 €1,952 4 2000 2000 T-in Constrained €1,771 €296 €2,067

Table 13 BritNor / Dogger Bank A OWF T-in cost comparison to Base Case

€ 0

€ 500

€ 1,000

€ 1,500

€ 2,000

€ 2,500

1 2 3 4

Scenario

Cos

t (m

)

Wind farm connection cost (€m)Interconnector cost (€m)

Figure 21 BritNor / DoggerBank A OWF T-in cost comparison to Base Case

6.3 Nordlink - DanTysk/Sandbank OWF Group T-in

The design for the Nordlink Interconnector in the ENTSO-E 10year development plan is for a 1400MVA rated HVDC +/-500kV bipole using Current Source Converters between Feda and Northern Germany. The Dan Tysk and Sandbank offshore wind farms have been determined by WP4 to have a combined capacity of 800MW. Hence the four scenarios/designs for which capital costs have been determined are given in Table 14 below with reference to Figure 20 and Figure 22.

Scenario Bipole

Section A (MVA)

Bipole Section B (MVA)

Windfarm Connection

Potential NO – GB Arbitrage

Potential Windfarm

Output 1 1400 1400 Direct to Germany Unconstrained Unconstrained 2 1400 1400 Interconnector Constrained Constrained 3 2000 1400 Interconnector Constrained Constrained 4 2000 2000 Interconnector Constrained Constrained

Table 14 Nordlink / Dan Tysk-Sandbank Interconnector T-in scenarios


Figure 22 Graphical representation of Nordlink/Dan Tysk- Sandbank OWF T-in

Norway Nordlink I/C CSC NO

+/-500kV DC Bipole (Section A)

Dantysk/Sandbank (800MW) VSC station

+/- - 500kV DC (Section B) Nordlink I/C CSC DE station

Germany

Sandbank OWF


Illustration Case

Case 17:

Clustered WF 2030

Case 18:

Nordlink & Dan Tysk and Sandbank WF T connection – planned capacity



Illustration Case

Case 19:

Nordlink & Dan Tysk and Sandbank WF T connection – 2000MW capacity to DE only


Case 20:

Nordlink & Dan Tysk and Sandbank WF T connection – 2000MW capacity to DE and NO


Table 15 Nord.Link - DanTysk & Sandbank T-in cases

6.3.1 Nordlink - DanTysk/Sandbank OWF Group T-in Capital Costs

Sandbank and DanTysk were clustered with another project called Nördlicher Grund in the hub costing phase, however only Sandbank and DanTysk have been added to the Nord.Link T connection for the initial study. Adding the Nördlicher Grund project would take up an excessive


capacity on the interconnector and leave little capacity for arbitrage. Subsequent iterations between WP5 and WP6 will alter the capacity of wind added to the T in connection depending on the market simulation. The results therefore show the cost of removing Nördlicher Grund from the hub and adding a radial connection to the onshore transmission system.

Scenario Section A (MW)

Section B (MW)

Wind farm Connection Constraint I/C Cost

(€m)

WF connection

cost (€m)

Cost (€m)

Base Case 1400 1400 Radial Direct to

Germany Unconstrained €1,167 €1,302 €2,469

1 1400 1400 Base Case Direct to Germany Unconstrained €1,167 €846 €2,013

2 1400 1400 Interconnector Constrained €1,167 €683 €1,850 3 2000 1400 Interconnector Constrained €1,276 €683 €1,959 4 2000 2000 Interconnector Constrained €1,431 €683 €2,114

Table 16 Nordlink / Dan Tysk-Sandbank OWF T-in cost comparison

€ 0

€ 500

€ 1,000

€ 1,500

€ 2,000

€ 2,500

€ 3,000

Base Case Scenario 1 Scenario 2 Scenario 3 Scenario 4

Mill

ions

Clustered (Sandbank, DanTysk &Nördlicher Grund)Base Case (Sandbank, DanTysk &Nördlicher Grund)Nördlicher Grund Radial

Sandbank DanTysk T

NordLink

Figure 23 Nordlink / Dan Tysk-Sandbank OWF T-in cost comparison


7 MESHED OFFSHORE GRID CASE STUDY

The initial step towards analysis of a Northern Europe Offshore Grid was to look at a case study between Norway, Germany and the United Kingdom. The basis for the meshed offshore grid is the offshore hubs that have been established previously to collect power from the offshore wind farm projects. The three countries in the case study all have onshore AC grids although not in synchronisation with each other and this along with the very long cable distances required means HVDC transmission is the optimal technology for interconnection. As an initial input to the economic model the technical design and capital cost has been assessed for new interconnections between these three countries only. An interconnection between hubs introduces the possibility to transfer power between countries however the energy exchange can be constrained depending on the power output of the offshore windfarms. Therefore for comparison a direct unconstrained interconnector between the onshore connection point substations has been designed and costed. Both the hub interconnections and direct links will be evaluated in the economic model. The hub to hub and direct links are shown in Table 17 and Figure 24 and Figure 25. 1000MW has been chosen as the initial building block input to the economic modelling between the three countries in the case study with the exception of the link between the UK and Norway. Iterations with the economic model will determine the optimum capacity for the interconnections and may even determine that they are not needed at all. The voltage level for the interconnections between hubs has been chosen to match the voltage of the hubs. This is because unlike with AC transmission, voltages in HVDC systems cannot be stepped up or down with transformers, instead they require DC to DC converters. DC to DC converters are technically feasible but have not been included in the first phase of modelling due to the expense of the converters themselves as well as their installation offshore. Should a need case for inter DC connection offshore be demonstrated within the economic model results than a suitable design will be proposed and costed in the second phase of modelling.

No. Type From To Offshore Distance

(km)

Capacity (MW)

Voltage (kV)

1 Hub GB Dogger Bank A Offshore DC 300kV NO Idunn Offshore DC

300kV 216 900 300

2 Direct GB Hornsea NO Lista 628 900 500

3 Hub GB Dogger Bank E Offshore DC 500kV DE Gaia Group

Offshore DC 500kV 232 1000 500

4 Direct GB Grimsby South DE Diele 486 1000 500

5 Hub DE Horizont Group Offshore DC 300kV NO AEgir Offshore DC

300kV 217 1000 300

6 Direct DE Diele NO Lista 494 1000 500

Table 17 Offshore Grid case study interconnections

7.1 Capital Costs

Costings for both cases are shown in Table 18 and Figure 26. The hub interconnections have a lower capital cost compared to the hub design and the direct links, but this must be assessed against the amount of power that will be transferred on the link given that it will be constrained at times depending on the wind farm power outputs. This assessment will be provided by the economic model and will drive the creation of other links where required between offshore hubs or onshore connection points to create the full offshore grid design.


Figure 24 Case study with interconnections between DE, GB and NO hubs

1 5

3


Figure 25 Case study with direct interconnections between DE, GB and NO

2

6

4


Option Type Link (€m)

Total Hub Costs (€m)

Total Hub Capacities

(MW)

Total Cost (€m)

Max Energy

Exchange (MW)

Min Energy

Exchange (MW)

Exchange

1 Hub € 363 € 1,272 1,900 € 1,636 900 0 Constrained 2 Direct € 1,261 € 1,272 1,900 € 2,533 900 900 Unconstrained 3 Hub € 531 € 3,198 3,510 € 3,729 1,000 0 Constrained 4 Direct € 1,348 € 3,198 3,510 € 4,547 1,000 1,000 Unconstrained 5 Hub € 365 € 1,822 1,980 € 2,188 1,000 0 Constrained 6 Direct € 1,271 € 1,822 1,980 € 3,094 1,000 1,000 Unconstrained

Table 18 Capital costs for interconnection options

€ 0

€ 500,000,000

€ 1,000,000,000

€ 1,500,000,000

€ 2,000,000,000

€ 2,500,000,000

€ 3,000,000,000

€ 3,500,000,000

€ 4,000,000,000

€ 4,500,000,000

€ 5,000,000,000

GB - NO GB - DE DE - NO

Hubs + Direct Links

Hubs + Interconnections

Figure 26 Capital cost for hub design and hub interconnectors compared to hub design and direct

interconnectors

The cases studied are shown in Table 19. Economic modelling has been performed for each of the cases in Work Package 6 and conclusions drawn in Work Package 8.


Illustration Case

Case 21:

Cluster WF (2030) plus additional GB‐NO 900MW interconnector

Effect of increased arbitrage potential

Case 22:

Cluster WF (2030) plus additional interconnector between Dogger Bank A (GB) and Idunn(NO) clusters

Cost benefit effect of capital cost against reduced arbitrage


Illustration Case

Case 23:

Cluster WF (2030) excluding BritNor interconnector plus additional interconnector between Dogger Bank A (GB) and Idunn (NO) clusters


Case 24:

Cluster WF (2030) plus additional interconnector between Dogger Bank A (GB) and Idunn (NO) clusters, plus additional separate 900MW GB‐NO interconnector



Illustration Case

Case 25:

Cluster WF (2030) plus additional GB‐DE interconnector


Case 26:

Cluster WF (2030) plus additional interconnector between Dogger Bank E(GB) and Gaia (DE)clusters



Illustration Case

Case 27:

Cluster WF (2030) excluding Nemo (GB‐BE) interconnector plus additional


Case 28:

Cluster WF (2030) plus additional GB‐DE, GB‐NO, and NO‐DE interconnectors



Illustration Case

Case 29:

Cluster WF (2030) plus additional interconnector between Dogger Bank E(GB) and Gaia (DE)clusters, additional interconnector between Dogger Bank A (GB) and AEgir (NO) clusters, and additional interconnector between Horizont (DE) and AEgir (NO) clusters


Table 19 Meshed offshore grid case study cases modelled in WP6

Figure 27 shows an example topology of a hub interconnection between 2 countries with different AC grids. The minimum requirement for switchgear is to have disconnecting devices on each offshore platform to disconnect sections of the network. As discussed earlier in the report this does not provide the necessary protection to remove faulted sections of network and maintain the operation of the un-faulted sections in the event of a fault on a cable or HVDC converter station. To achieve this, the design could also include DC circuit breakers if required by the owner or operator of the DC grid. If the Offshore Grid design had multiple infeeds to the same AC onshore grid then DC breakers would be required if the resulting infeed loss to the onshore system were to exceed the Frequency Control Reserve levels held by the onshore TO’s. HVDC circuit breakers may also be required by Offshore Grid operators between ownership boundaries to minimise the impact of faults on the Offshore Grid propagating between the respective owners network.


Figure 27 Example Hub to Hub DC connection


8 CONCLUSIONS

As the results from this first phase of the OffshoreGrid Work Package 5 modelling work are being assessed against the output from the economic modelling as part of Work Package 6 it is not possible to draw conclusions within this report as to the economically optimal nature of the design assumptions and network topologies proposed so far, as this will become evident flowing further iterations between the two modelling packages. However what can be concluded is that clustering certain offshore wind farms together to share onward transmission assets creates significant reductions in capital cost (17% or €14bn savings by 2030) and also reduces the amount of cable required which could ease potential supply chain constraints. It can also be concluded that connecting the offshore wind farms identified in the case studies into the adjacent interconnectors also generates capital cost savings of 14% or €290m in the case of Dogger Bank A wind farm and BritNor and 8% or 163€ in the case of the Dan Tysk & Sandbank wind farms and Nordlink, however whether this is an economically efficient proposal from a European consumer perspective will depend on the constraints introduced on arbitrage between Great Britain and Norway , and Norway and Germany respectively as a result. While it is logical to assume that connecting wind farms to adjacent interconnectors is always going to reduce capital costs, the level of reduction if any is very much dependent on issues such as project capacity, distance to onshore connection point, interconnector capacity and distance to the nearest interconnector making it difficult to draw generic conclusions as to when a project should be T-in connected to an interconnector, however carrying out more case studies as part of the second phase of works should help to clarify this boundary. The preliminary designs for a true interconnected offshore grid between Great Britain, Norway and Germany show that using the offshore wind farm cluster hubs as the connecting points for inter country interconnectors creates significant savings 24% or €2.6bn over the alternative of having stand alone direct links between those same countries, however again this conclusion needs to be balanced against the value of lost arbitration (assessed within work package 6) which will result before the design can be deemed economically efficient for the European consumer.


Case Results

Number Description Effects under Examination Total Wind farm

Connection Asset Cost (€m)

Total Interconnector

Asset Cost (€m)

Total Cost (€m)

Section Reference Notes

Base Case (North & Baltic Seas)

1 Base Case (2010) 2010 reference: € 1,439 € 0* € 1,439 Section 4

* There is no interconnector cost identified in the 2010 base case as existing interconnectors are deemed to be part of the existing transmission network

2 Base Case (2020) Business as usual, i.e. individual radial connections for all projects commissioned up to 2020

€ 25,313 € 6,309 € 31,622 Section 4

3 Base Case (2030) Business as usual, i.e. individual radial connections for all projects commissioned up to 2030

€ 83,201 € 6,309 € 89,510 Section 4

Clustered Wind Farms Case (North & Baltic Seas)

4 Clustered WF (2030) Where applicable, wind farms are clustered offshore to share connection assets to shore

€ 69,096 € 6,309 € 75,405 Section 5

Due to economic and phasing reasons some wind farms remain radially connected. Note also that no wind farms have been connected to interconnectors in this case

GB-NO Interconnector /Offshore Wind Farm T connection Case Studies

5 Base Case 2030 BritNor & Dogger Bank A

BritNor Interconnector and Dogger Bank A 1000MW wind farm connection costs in isolation for

€ 69,096 € 6,309 € 75,405 Section 6 Used for comparison against the later cases


Case Results




Asset Cost (€m)

Total Cost (€m)


comparison

6 BritNor/Dogger Bank A T connection – planned capacity

To assess capital cost savings against arbitrage constraints €68,805 € 6,310 €75,115 Section 6

Dogger Bank A WF connected to BritNor interconnector, no other change to interconnector capacity

7

BritNor/Dogger Bank A T connection – 2000MW capacity to UK only


€ 68,805 € 6,519 € 75,324 Section 6

Dogger Bank A connected to BritNor with capacity increased to 2000MW on UK connected leg only

8

BritNor/Dogger Bank A T connection – 2000MW capacity to UK and NO


€ 68,805 € 6,634 € 75,439 Section 6

Dogger Bank A connected to BritNor with capacity increased to 2000MW on both UK & NO connected legs

GB-NO Interconnector /Offshore Wind Farm T connection Sensitivity Studies – Reduced Wind Farm Capacity (500MW)

9 Clustered WF (2030) € 69,096 € 6,309 € 75,405 Section 5 Used for comparison against the later cases

10 BritNor/500MW OWF T connection – planned capacity

BritNor Interconnector with 500MW wind farm at Dogger Bank A location T – connection , and remaining 500Mw connected directly to shore

€69,111 € 6,310 €75,421 Section 6

500MW WF at Dogger Bank A location connected to BritNor interconnector, no other change to interconnector capacity

11

BritNor/500MW OWF T connection – 2000MW capacity to UK only


€ 69,111 €6,519 € 75,630 Section 6

500MW WF connected to BritNor with capacity increased to 2000MW on UK connected leg only

12 BritNor/500MW OWF T connection – 2000MW capacity to


€ 69,111 € 6,634 € 75,745 Section 6 500MW WF connected to BritNor with capacity increased to 2000MW on


Case Results




Asset Cost (€m)

Total Cost (€m)


UK and NO both UK & NO connected legs GB-NO Interconnector /Offshore Wind Farm T connection Sensitivity Studies – Additional GB – NO 900MW Interconnector

13

BritNor/Dogger Bank A T connection at planned capacity plus additional interconnector

To assess capital cost against reduced arbitrage constraints € 68,805 € 7,171 € 75,976 Section 6

Dogger Bank A WF connected to BritNor interconnector, plus additional separate interconnector

14

BritNor/Dogger Bank A T connection – 2000MW capacity to UK only plus additional interconnector


Dogger Bank A connected to BritNor with capacity increased to 2000MW on UK connected leg only plus additional separate interconnector

15

BritNor/Dogger Bank A T connection – 2000MW capacity to UK and NO plus additional interconnector


Dogger Bank A connected to BritNor with capacity increased to 2000MW on both UK & NO connected legs plus additional separate interconnector

GB-NO Interconnector /Offshore Wind Farm T connection Sensitivity Studies – BritNor Interconnector Omitted

16 Base Case 2030 With Dogger Bank A but BritNor removed

Interconnector (excluding BritNor) and Dogger Bank A 1000MW wind farm connection costs in isolation for comparison

€69,096 €5,124 €74,220 Section 6 Used for comparison against the other cases

DE-NO Interconnector / Offshore Wind Farm T connection Case Studies


Case Results




Asset Cost (€m)

Total Cost (€m)


17 Clustered WF 2030 € 69,096 € 6,309 € 75,405 Section 5 Used for comparison against the later cases

18

Nordlink & Dan Tysk and Sandbank WF T connection – planned capacity

To assess capital cost savings against arbitrage constraints € 68,933 €6,309 € 75,242 Section 6

Dan Tysk and Sandbank WF connected to Nordlink interconnector, no other change to interconnector capacity. Nordlicher Grund project connected directly to shore

19

Nordlink & Dan Tysk and Sandbank WF T connection – 2000MW capacity to DE only


€ 68,933 € 6,418 € 75,351 Section 6

Dan Tysk and Sandbank WF connected to Nordlink interconnector with capacity increased to 2000MW on DE connected leg only

20

Nordlink & Dan Tysk and Sandbank WF T connection – 2000MW capacity to DE and NO


€ 68,933 € 6,573 € 75,506 Section 6

Dan Tysk and Sandbank WF connected to Nordlink interconnector with capacity increased to 2000MW on both DE & NO connected legs

GB-NO Interconnecting Clusters vs Direct Interconnector Case studies

21

Cluster WF (2030) plus additional GB-NO 900MW interconnector

Effect of increased arbitrage potential € 69,096 € 7,170 € 76,266 Section 7 For comparison with later

cases

22 Cluster WF (2030) plus additional interconnector

Cost benefit effect of capital cost against reduced arbitrage € 69,096 € 6,570 € 75,666 Section 7


Case Results




Asset Cost (€m)

Total Cost (€m)


between Dogger Bank A (GB) and Idunn(NO) clusters

23

Cluster WF (2030) excluding BritNor interconnector plus additional interconnector between Dogger Bank A (GB) and Idunn (NO) clusters


24

Cluster WF (2030) plus additional interconnector between Dogger Bank A (GB) and Idunn (NO) clusters, plus additional separate 900MW GB-NO interconnector

Cost benefit effect of capital cost against reduced arbitrage € 69,096 €7,431 € 76,527 Section 7

GB-DE Interconnecting Clusters vs Direct Interconnector Case studies

25 Cluster WF (2030) plus additional GB-DE interconnector


cases

26

Cluster WF (2030) plus additional interconnector between Dogger Bank



Case Results




Asset Cost (€m)

Total Cost (€m)


E(GB) and Gaia (DE)clusters

27

Cluster WF (2030) excluding Nemo (GB-BE) interconnector plus additional interconnector between Dogger Bank E (GB) and Gaia (DE) clusters


GB-DE-NO Interconnecting Clusters vs Direct Interconnector Case studies

28

Cluster WF (2030) plus additional GB-DE, GB-NO, and NO-DE interconnectors


cases

29

Cluster WF (2030) plus additional interconnector between Dogger Bank E (GB) and Gaia (DE) clusters, additional interconnector between Dogger Bank A (GB) and AEgir (NO) clusters and additional interconnector between Horizont (DE) and AEgir (NO) clusters



Case Results




Asset Cost (€m)

Total Cost (€m)


CO2 Price Economic Model Sensitivity Studies

30 Clustered WF (2030) High CO2 Price

Effect of high CO2 Price on economic model € 69,096 € 6,309 € 75,405 Section 5


31 Clustered WF (2030) Low CO2 Price

Effect of low CO2 Price on economic model € 69,096 € 6,309 € 75,405 Section 5


32

Cluster WF (2030) plus additional GB-DE, GB-NO, and NO-DE interconnectors High CO2 Price

Effect of high CO2 Price on economic model € 69,096 € 8,943 € 78,039 Section 7

33

Cluster WF (2030) plus additional interconnector between Dogger Bank E(GB) and Gaia (DE)clusters, additional interconnector between Dogger Bank A (GB) and Sorlige

Effect of low CO2 Price on economic model € 69,096 € 7,043 € 76,139 Section 7


Case Results




Asset Cost (€m)

Total Cost (€m)


Nordsjoen (NO) clusters, and additional interconnector between Horizont (DE) and AEgir (NO) clusters Low CO2 Price

Table 20 Cases studied summary table


9 REFERENCES

[1] Ten-Year Network Development Plan 2010 – 2020, ENTSO-E, 28/06/2010 [2] AMENDMENT REPORT SQSS Review Request GSR007 - Review of Infeed Loss Limits,

SQSS Review Group, Issue 1.0, 10th September 2009 [3] P1 – Policy 1: Load-Frequency and Control Performance Document, ENTSO-E, 2009 [4] Nordel System Operation Agreement (2006), Nordel, 2006 [5] THE CROWN ESTATE Round 3 Offshore Wind Farm Connection Study – Appendix 1:

Offshore Wind Farm installed capacity/connection capacity, S. Cowdroy, Econnect, December 2008

[6] Predrag Djapic and Goran Strbac, Cost Benefit Methodology for Optimal Design of Offshore Transmission Systems, Centre for Sustainable Electricity and Distributed Generation (SEDG), July 2008

[7] Siemens Press Release – Siemens receives order from transpower to connect offshore windfarms via HVDC link, Energy Sector – Power Transmission Division, Erlangen, Germany, June 11, 2010

[8] ABB Press Release – ABB wins order for offshore wind power connection worth around $ 700 million, Zurich, Switzerland, July 16 – ABB

[9] AREVA and Dutch Consortium Partner Keppel Verolme B.V.Win Major Offshore Substation Contract in Germany, http://tdworld.com/projects_in_progress/business_in_tech/areva-keppel-verolme-0510/ , Transmission & Distribution World, May 13, 2010

european offshoregrid site requirements and connection report

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