THE CROWN ESTATE
Round 3 Offshore Wind Farm Connection Study
Version 1.0
Prepared for
Danielle Lane
The Crown Estate
16 New Burlington Place
London
W1S 2HX
Executive Summary
This investigation presents an indicative set of optimum offshore and onshore electricity
transmission network reinforcements required for the connection of up to 25GW of offshore wind
generation as part of the Round 3 leasing process. It has been carried out by Senergy Econnect
and National Grid for the Crown Estate to aid in the development of the potential Round 3
development zones published earlier in the year. The final location of these zones is subject to the
outcome of the Strategic Environmental Assessment currently being undertaken by the
Department for Energy and Climate Change (DECC; formerly BERR) and further work with project
developers.
As the aim of this study was to identify the extent and costs of the works necessary to provide
optimised transmission connections for all of the Round 3 offshore wind farms, an analysis was
undertaken by Senergy Econnect as an annex to this report to ascertain at a high level the optimal
ratio between the installed generating capacity offshore and the transmission capacity of the
offshore transmission assets. This optimal utilisation ratio was determined to be 112%. In practice
the offshore transmission asset designs provided in this report have a range of utilisation ratios
from 81% to 112% because of the zonal capacities identified by The Crown Estate and the
modular nature of the transmission assets themselves (with each additional cable providing a fixed
increase in transmission capacity). National Grid are in the process of leading a review of the
security standards for offshore generation connections to include projects of the size and distance
form shore associated with Round 3, at the request of Ofgem. This review will culminate in a set of
security recommendations including offshore transmission circuit capacity, which will be consulted
upon and incorporated as revised text in the GB SQSS.
In order to provide as accurate a cost model as possible a number of high voltage power
equipment manufacturers and installers were consulted for the current costs of the equipment that
would be required to realize the offshore connection designs described in this report.
The offshore connection designs have been based around indicative zonal capacities provided by
The Crown Estate. The location and installed capacities of the wind farms located within the zones
as identified in this report have been determined by Senergy Econnect based on the principle of
minimising the offshore transmission assets required for connection and identifying the associated
costs. As such these designs may not provide the optimal solutions for the actual Round 3 wind
farms, as the location, installed capacity, and offshore transmission technology and utilisation
factor for the actual wind farms will be determined by the zonal developer and offshore
transmission owner in collaboration with the selected technology provider. These solutions are
designed to comply with the offshore GB SQSS proposals, except where expressly stated.
The following Table summarises the optimal cost of connections resulting from this analysis.
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ZONE
OWF
Total
Installed
Capacity
Connection
technologies
Connection Point
(s)
TOTAL
COST
TOTAL
COST
Per MW
Moray Firth
C
500MW
AC
New substation on
coast
£193m*
£386k
Firth of Forth
G
500MW
AC
Torness
£150m*
£300k
H1
1237.5MW
DC
Creyke Beck
£5,910m
£477k
H3
1237.5MW
DC
Creyke Beck
J
1240MW
DC
Creyke Beck
H2
1237.5MW
DC
Keadby
H4
1237.5MW
DC
Keadby
H5
1237.5MW
DC
Killingholme
I1
1240MW
DC
Killingholme
I2
1240MW
DC
Killingholme
M
1237.5MW
DC
New substation on
Lincolnshire coast
N
1240MW
DC
New substation on
Lincolnshire coast
T
1240MW
AC
Sizewell
£1,728m
£349k
Z2
1240MW
DC
Sizewell
U
1237.5MW
DC
Norwich
Z1
1237.5MW
DC
Norwich
Hastings
AA
500MW
AC
Bolney
£184m
£368k
West Isle of
Wight
DA
500MW
AC
Chickerell
£175m
£350k
Bristol
Channel
EA
1500MW
AC
New substation on
Torridge Estuary
£430m
£287k
IA
1237.5MW
DC
Deeside
£1,632m
£329k
LA
1240MW
DC
Deeside
JA
1237.5MW
AC
Wylfa
NA
1240MW
DC
Stanah
£10,402m
£403k
Dogger Bank
Hornsea
Norfolk
(without
Sizewell C)
Irish Sea
TOTALS
25,795MW
Table 1: Optimal Connection Costs broken down by Zone
*Total reinforcement costs dependent on GB transmission owner study currently in progress
The total cost for connecting the round 3 wind farm projects, assuming no inclusion of Sizewell C,
and the optimal design solutions identified in this report is £10,402 million. . Note that this Figure is
based on 2008 price levels for the equipment required and does not allow for the additional
equipment such as Static Var Compensation that may need to be installed at the onshore
connection point of the HVAC connection solutions in order for the Offshore Transmission Owners
to meet the reactive capability requirement of the System Operator/Transmission Owner code (e.g.
an SVC sufficient to provide dynamic reactive capability for a 300MW wind farm would cost in the
order of £12m).
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Sensitivities were also investigated in some areas where new nuclear developments could occur in
the same region and within the same timescales as the Round 3 development. If transmission
reinforcement was not undertaken in an optimised manner on a strategic basis then offshore
transmission asset costs could increase as a result of having to find alternative more distant
connection points. An example of this is the Norfolk zone where the inclusion of Sizewell C
increases the offshore transmission asset cost by £245m.
As a function of these designs, the total installed generating capacity connected for round 3 is
25,295MW (with a connection capacity of 22,980MW) with a £/MW cost ranging from £287k to
£477k.
In undertaking this work it became clear that, from a purely economic perspective, minimising the
length of the offshore transmission network as much as possible is desirable. Typically the cost of
the offshore network comprised roughly 90% of the total reinforcement cost. However, the need for
significant onshore reinforcement, and the consenting risk that accompanies this reinforcement,
was also identified. This was particularly the case for connection of the Dogger Bank, Hornsea and
Norfolk development zones as well as areas with the potential for connection of new nuclear
generation. Nevertheless, National Grid is confident that the network can be developed in an
economic and efficient manner to facilitate renewable targets. In order to achieve this aim, work will
need to occur in a timely manner, which implies that some of it may have to occur before specific
individual projects materialise. The possible need for investment on an anticipatory ‘no regret’
basis and the pressure to meet renewables targets places further emphasis on the importance of a
coordinated approach to the design of an optimum offshore and onshore specific solution.
Where onshore reinforcement options have been identified through this study, no environmental
impact assessment of these reinforcements has been undertaken at this stage. Prior to
undertaking any onshore reinforcement’s environmental impact assessments will be undertaken in
accordance with best practice against a range of possible solutions.
Some of the identified reinforcements will require planning consent and for this reason the
Planning Bill, which received Royal Assent on 26 November, is seen as an essential process to
enable significant energy infrastructure projects to be constructed, while enabling local
communities and stakeholders to fully engage in the process . Identification of specific onshore
reinforcements and the timing of these reinforcements are subject to the frameworks that currently
govern the development of the transmission system such as the transmission access regime and
the Great Britain Security and Quality of Supply Standards (GB SQSS). The onshore transmission
owners are currently in the process of a fundamental review of these frameworks to ensure that
they are fit for purpose for a GB electricity system that incorporates large volumes of variable
generation from renewable sources.
The power transfer capabilities of the HVAC and HVDC technologies available coupled with the
potential installed capacity of the Round 3 OWF have to a large part dictated the offshore
transmission designs presented in this report and determined that in the primary solution each
OWF is connected directly to an onshore connection point, with no interconnection between the
OWF in a particular zone.
Applying an HVAC and HVDC solution to the same OWF has indicated that the choice of
technologies used for the offshore transmission designs will be dictated by the transmission
distance and that the cable route length at which HVDC Voltage Source Converter solutions
become more economic than an equivalent HVAC solution is between 60km and 80km.
Aggregated solutions, where multiple OWF are interconnected have been considered and costed,
although these solutions do not compare favourably with the individual offshore transmission
designs for the same OWFs in terms of cost per MW installed, except where solutions have been
considered that utilise dual bipole HVDC overhead lines as opposed to underground cable to
traverse the long distance overland routes from the coast to Norwich and Drax substations.
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The challenges posed in delivering the Round 3 offshore connections, regardless of design
pursued, will be significant. Investment will be required by existing suppliers in expanding
manufacturing facilities for HV cables, and in particular subsea cables. The HVDC VSC market is
still at an embryonic stage, with the converter/bipole ratings used in this report yet to be deployed
in the field. Hence there will be a technology risk as well as cost premium to be borne by the ‘first
comer’ offshore transmission owner to specify this technology. Again it is likely that manufacturing
facilities would need to be expanded to accommodate demand should Round 3 be developed in
the timescales desired, with prices dropping as competition increases and with economies of scale.
The HVDC converter manufacturers are confident that they can increase manufacturing capability
to meet demand should they have sufficient assurance that projects will place orders. However
Senergy Econnect have anecdotal evidence that one manufacturer is revising downwards their
short to medium term forecasts for supplying the offshore market in the UK because of the delays
in progressing offshore projects through the GB planning, consenting, and regulatory process, and
the ability of the process to deliver the offshore wind farm capacity in the timescales desired.
It should be noted that the offshore programmes of other countries and an increase in HVDC
projects around the world will coincide with the Round 3 build programme, and hence Round 3
developers or their Offshore Transmission Owners may potentially need to commit to production
slots up to three or more years in advance to avoid the HVDC converters becoming a constraint.
In order for the HVDC suppliers to have the confidence to increase their manufacturing capability,
they will require an order book to be in place, which in turn means that the Offshore Transmission
Owner regime needs to ensure that the procurement of equipment is triggered as early as possible
in the process so that these lead times can be managed and reduced.
Suppliers of the installation vessels necessary to install the cables and offshore platforms are
bullish in their ability to quickly ramp up capacity to meet the demands of Round 3, although they
acknowledge that to make the investment required in the timescales necessary they will need the
security of retainer agreements or firm orders in place.
The design and costing process has considered a “total solution” capable of handling the entire 25
GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms
in a zone are required and that the overall onshore transmission system changes will all occur in a
coordinated manner at any one location. Should piecemeal developments be undertaken, wind
farm-by-wind farm, and/or wind generation capacity change incrementally over a period of years,
the staggered timing of the works would result in multiple site/circuit extensions and this will
increase the overall onshore costs and environmental impact. In order to avoid this extensive
stakeholder engagement, coordination and collaboration is required.
The report recommends that next steps should include a more detailed investigation of the
environmental and planning constraints associated with the Round 3 zone connections and of the
supply chain challenges likely to confront Round 3 projects. Further investigation into possible ‘no
regret’ onshore reinforcements that have the potential to reduce the total connection cost would
also be beneficial
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Table of Contents
Executive Summary .......................................................................................................................... 3
1
Introduction.......................................................................................................................... 10
2
Overall Design Methodology ............................................................................................... 12
3
Offshore Design Methodology ............................................................................................. 14
3.1
Establishing wind farm capacity & location.......................................................................... 14
3.2
Establishing number and location of offshore platforms...................................................... 17
3.3
Connection link technologies, capabilities and limitations ................................................... 18
3.3.1
AC cables ................................................................................................................ 18
3.3.2
HVDC....................................................................................................................... 20
3.3.2.1
Current Source Converter HVDC technology .......................................................... 21
3.3.2.2
Voltage Source Converter HVDC technology.......................................................... 21
3.3.3
Gas Insulated Transmission Lines........................................................................... 24
3.3.4
Superconductors...................................................................................................... 25
3.4
Establishing offshore redundancy, security & quality of supply criteria ............................... 26
3.5
Tailoring Installed Capacity to Connection Capacity ........................................................... 28
3.6
Assessing landfall points, onshore cable routes & land availability..................................... 29
3.7
Assessing offshore cable routes.......................................................................................... 29
4
Offshore Cost Methodology................................................................................................. 31
5
Onshore Design................................................................................................................... 37
5.1
Assessing requirements for additional capacity on the onshore transmission system ........ 37
5.2
Scenario – Background assumptions on generation and demand ...................................... 38
5.3
Onshore Transmission Requirements: Methodologies for Costing and Option Analysis .... 39
5.4
Cost Basis ........................................................................................................................... 39
5.5
Option Analysis.................................................................................................................... 41
Zones with only one or two wind farms and relatively small overall capacities (1500 MW or less). 41
Zones with several wind farms and larger capacities (approx. 3000 – 11000 MW) ........................ 41
5.6
Scottish System Area .......................................................................................................... 41
6
Overall Design Options and Potential Zonal Solutions........................................................ 41
6.1
Moray Firth .......................................................................................................................... 42
6.1.1
Offshore connection................................................................................................. 43
6.1.2
Offshore connection alternatives ............................................................................. 43
6.1.3
Onshore reinforcement ............................................................................................ 43
6.2
Firth of Forth ........................................................................................................................ 44
6.2.1
Offshore connection................................................................................................. 45
6.2.2
Offshore connection alternatives ............................................................................. 45
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6.2.3
6.3
Onshore reinforcement ............................................................................................ 45
Dogger Bank & Hornsea...................................................................................................... 46
6.3.1
Offshore connection................................................................................................. 52
6.3.2
Offshore connection alternatives ............................................................................. 53
6.3.3
Onshore reinforcement ............................................................................................ 56
6.4
Norfolk ................................................................................................................................. 59
6.4.1
Offshore connection................................................................................................. 62
6.4.2
Offshore connection alternatives ............................................................................. 62
6.4.3
Onshore reinforcement ............................................................................................ 63
6.4.3.1
Zonal Infrastructure Works (without Sizewell C) ...................................................... 64
6.4.3.2
Zonal Infrastructure Works (with Sizewell C) ........................................................... 66
6.5
Hastings............................................................................................................................... 67
6.5.1
Offshore connection................................................................................................. 67
6.5.2
Offshore connection alternatives ............................................................................. 68
6.5.3
Onshore reinforcement ............................................................................................ 68
6.6
West Isle of Wight................................................................................................................ 70
6.6.1
Offshore connection................................................................................................. 70
6.6.2
Offshore connection alternatives ............................................................................. 71
6.6.3
Onshore reinforcement ............................................................................................ 71
6.7
Bristol Channel .................................................................................................................... 73
6.7.1
Offshore connection................................................................................................. 74
6.7.2
Offshore connection alternatives ............................................................................. 75
6.7.3
Onshore reinforcement ............................................................................................ 75
6.8
Irish Sea .............................................................................................................................. 77
6.8.1
Offshore connection................................................................................................. 77
6.8.2
Offshore connection alternatives ............................................................................. 79
6.8.3
Onshore reinforcement ............................................................................................ 80
7
Delivery Issues .................................................................................................................... 82
7.1
Offshore Installation & Manufacturing resource .................................................................. 82
7.1.1
HVAC and HVDC subsea cables............................................................................. 82
7.1.2
HVDC converter equipment..................................................................................... 83
7.1.3
Balance of plant equipment (e.g. transformers, switchgear, etc)............................. 83
7.1.4
Assessment of the availability and cost of cable installation vessels ...................... 83
7.2
Onshore transmission network delivery programme ........................................................... 84
8
Conclusions ......................................................................................................................... 85
8.1
Methodology and Assumptions ........................................................................................... 85
8.2
Cost of Connecting Round 3 Offshore Wind Farms ............................................................ 85
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8.3
Individual Versus Aggregated Connections......................................................................... 87
8.4
Deliverability of Round 3 Connections................................................................................. 87
8.5
Benefits of a co-ordinated approach.................................................................................... 88
9
Recommendations............................................................................................................... 90
10
References .......................................................................................................................... 91
11
List of Appendices ............................................................................................................... 92
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1
Introduction
Following the initial East Coast Transmission Network, Technical Feasibility Study [1] and
subsequent meetings with key stakeholders such as the Scottish Government, National Grid,
Ofgem, and the Department for Energy and Climate Change (DECC; formerly BERR), The Crown
Estate now wish to understand the potential extent and cost of the works necessary to provide
optimised transmission connections for the indicative Round 3 offshore wind farm project
development zones1. This includes an assessment of the necessary onshore reinforcements to
facilitate these connections, such that a coordinated, optimal design between onshore and offshore
is achieved.
A crucial starting point for this report was to establish the size and location of the offshore Round 3
projects that could arise within the areas identified. Once this was established the challenge was to
design a network topology with sufficient capacity to accumulate and transmit the power levels
required. Selecting an appropriate capacity for each connection link is also important in
establishing the financial case for such an offshore transmission scheme as the utilisation of these
offshore assets (as part of demonstrating an economic and efficient test) will likely be a significant
parameter in the competitive tender process to be overseen by Ofgem in awarding the Offshore
Transmission Owner licences.
As well as understanding the size and location of the planned generation projects, the type of
generation proposed is fundamental to designing a technically and economically efficient offshore
transmission system. This study is based on current, prototype or proposed offshore wind turbine
models that could achieve market realisation in the assumed timescales of the Round 3 projects.
The maximum amount of power that could be lost in the event of a fault on the offshore network is
of interest to the onshore system operator as they will need to put operational measures in place
for this possibility. The possible extent of this power loss with regard to the Round 3 project
timescales is discussed in Section 3.4.
Of significant impact to the final network topology is the location of the connection points to the
onshore networks within the geographical area of consideration and the reinforcements required to
the onshore system in order to facilitate these connections. The final choice of connection point
was determined iteratively by assessing the ability of the onshore networks to accept either a
power infeed or outflow at certain nodes, the land available to extend either existing substations or
create new substations, and the practicality and cost of either extending the 400kV overhead line
network or providing an onshore cable route.
This analysis was undertaken against generation background assumptions other than that of the
currently contracted generation projects (i.e. those having a Bilateral Connection Agreement with
the GB System Operator) that would normally be considered as part of a connection application
process. The overall optimum solutions presented could therefore change depending on which
generation projects actually come forward in future. Sensitivity studies have been undertaken on
key variables, such as nuclear replanting, in order to mitigate as far as possible the effect of this
future uncertainty.
1
Subject to the outcome of the DECC Strategic Environmental Assessment
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Once an asset optimised offshore and onshore design was achieved against the background
assumptions made, each design was costed, based on updated pricing information received from
Siemens, ABB, Areva, and Prysmian and the experience of National Grid in building onshore
assets.
There is currently a shortage of critical raw materials required for infrastructure development, such
as copper, aluminium, and steel, as well as potentially significant restrictions in the capacity
available to manufacture the elements of technology required to implement an offshore network
scheme. It should be noted that an offshore scheme spanning the geographical areas outlined for
Round 3 would also be beyond anything currently in operation. For this reason, a certain amount of
design and development work will need to be undertaken, (for example refinement of the
technology to support multi-terminal HVDC operation), before such a scheme could be
manufactured, constructed, and operated. The tools necessary to install subsea cables and
platforms, such as lifting barges and cable laying vessels, are also presently in short supply;
therefore, this study ascertains how these restrictions will impact the lead time necessary to
commission any proposed scheme.
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2
Overall Design Methodology
Engineering Design
Network Design
A key feature of this work is an investigation into a coordinated offshore and onshore design for the
connection of offshore wind generation, in an attempt to provide a more effective solution than
simply connecting to the nearest point onshore. At a high level, the process is illustrated in Figure
1.
Offshore Design
Iterative
Design
Process
Standards and
Assumptions
Onshore Design
Overall
Optimum
Network
Conclusions
Network and Turbine
Technology
Offshore and Onshore
Costs
Land, Planning,
Consents and
Network Installation
and
Recommendations
Figure 1: Iterative Offshore and Onshore Design Methodology
Projects arising out of the Round 1 and Round 2 offshore leasing process were predominantly
small in size and close to the shoreline (almost exclusively within the 12 nautical mile limit of
territorial waters) relative to the proposed Round 3 areas. For the majority of these Round 1 and
Round 2 projects, cost benefit analysis clearly demonstrated that individual, AC, radial connections
to the electricity system onshore were the most economic. In contrast, offshore areas earmarked
for Round 3, such as the Dogger Bank, could be developed to levels of up to tens of gigawatts and
are located more than 100km from the onshore system leaving greater scope for consolidation and
optimisation in taking the energy to shore.
The impact of where a project is connected to the onshore transmission system on connection
timescales and overall cost has often been underestimated in the past, occasionally leading to
unexpected revisions in assumptions on capital costs, additional consenting risk and the potential
for sub-optimal overall design. This highlights the impact of the effect on the onshore transmission
system as a result of a particular offshore design and the importance of the iterative nature by
which the design process must take place in order to find the optimum combination between
offshore and onshore assets. This is especially pertinent for projects of the size and geographically
diverse locations characteristic of those expected to arise out of the Round 3 process.
In considering the amount of transmission capacity required to facilitate the connection of the
indicative Round 3 development zones it is important to note that this was assessed relative to the
calculated potential capacity of these zones as well as the levels of electricity demand and the
amount and spatial distribution of conventional generation (such as coal, gas and nuclear)
assumed to share network capacity with onshore and offshore wind generation.
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The offshore network topology and technology is largely determined by the location of and
distance to the optimum connection points onshore. The final choice of connection point has been
determined by finding an economic balance between offshore and onshore reinforcement required,
including the cost of both local (substation and circuits) and wider (Main Interconnected
Transmission System (MITS)) reinforcement.
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3
Offshore Design Methodology
The starting point for this report was to establish the nominal capacity and location of the forecast
offshore Round 3 generation projects within the indicated, potential offshore zones for
development. Once this was established a connection network topology was constructed with
sufficient capacity to accumulate and transmit the power levels required. Selecting an optimum
capacity for the links in this connection network is also important in establishing the financial case
for such an offshore transmission scheme. Any offshore assets to be constructed under a
regulated regime will be assessed by Ofgem as part of a competitive tender process for awarding
Offshore Transmission Owner licences. Therefore demonstrating that these assets are designed to
achieve optimum utilisation will be a key consideration. The following sections describe the
methodology used to design and then cost the various Round 3 connection network topologies
contained within this report.
3.1
Establishing wind farm capacity & location
Following the public announcement of the third round of offshore wind farm site leasing in 2007,
The Crown Estate have published a map showing indicative Round 3 zones for development2 (see
Figure 2) however in order to arrive at a connection solution it was necessary to establish an
indicative MW capacity that will be connected within each of the zones and also the locations of
possible wind farm developments within each zone. To that end The Crown Estate allocated 25GW
across the nine zones approximately in relation to the area of the zone. The allocation was carried
out for the purposes of this study and is one of a number of possible scenarios for capacity
allocation. It does not necessarily reflect The Crown Estate’s view on the likely outcome of the
Round 3 tender. Additionally The Crown Estate provided a series of GIS shape files indicating
areas within each zone that could potentially become sites for offshore wind farms, hereafter
referred to as ‘Polygons’, as well as indicative connection capacities for each of the Round 3
development zones, (see Table 2 below).
Further it should be noted that this study does not take account of all environmental constraints.
Therefore the location of the development zones and polygons will be dependent not only on the
Round 3 tender but also on the outcome of the Strategic Environmental Assessment being
undertaken by DECC and any environmental Impact Assessment of individual sites.
2
Subject to the outcome of the DECC Strategic Environmental Assessment
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Figure 2: Round 3 Zones for Development
©Crown Copyright
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Round 3 Development Zone
Indicative Connection Capacity
(MW)
Moray Firth
500
Firth of Forth
500
Dogger Bank
9000
Hornsea
3000
Norfolk
5000
Hastings
500
West Isle of Wight
500
Bristol Channel
1500
Irish Sea
5000
25,500
TOTAL
Table 2: Round 3 Zonal Indicative Connection Capacities
In order to assess each polygon’s potential for installed capacity, and hence each polygon’s
contribution towards the zonal indicative connection capacity, it was necessary to establish a wind
turbine array within each polygon’s boundaries. For the purposes of this report, these arrays were
based on current, prototype, or proposed multi-MW wind turbine models that could achieve market
realisation in the timescales of the Round 3 projects.
Each polygon was allocated one of two wind turbine model types to maximise the power density
achieved to meet the zonal indicative connection capacity required. The arrays were constructed
based on standard wind farm turbine spacing principles of seven rotor diameters apart in the
prevailing wind direction and four rotor diameters apart in the direction perpendicular to the
prevailing wind [2]. The wind turbines used in this study and the corresponding array spacings are
shown in Table 3. Note that the wind turbine types used here do not represent an exhaustive list of
potential machines that could be used for the Round 3 offshore projects but as indicative wind
turbine capacities for the purposes of this report.
Turbine type
REpower
5M
Clipper Wind
Britannia
Capacity
Rotor Diameter
Prevailing wind
array spacing
Perpendicular
array spacing
5MW
126m
882m
504m
7.5MW
150m
1050m
600m
Table 3: Wind turbines utilised and corresponding array spacings
Each wind farm’s array was orientated as far as possible to the prevailing wind direction in the UK,
i.e. from the South West, and the potential power capacity established. Some of the polygons
could accommodate far more wind turbines than required to meet the zonal indicative connection
capacity, and hence the arrays in this case were limited by the connection capacity available
and/or the contribution required to the zonal indicative connection capacity (see Figure 3). Some
polygons were excluded from the connection designs in zones where the potential connection
capacity of the polygons exceeded the zonal indicative connection capacity provided by The Crown
Estate. The zonal and wind farm capacities arrived at are shown in Table7.
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Figure 3: Hastings Zone showing potential and utilised array area
(KEY: Green Dot – Wind Turbine
3.2
Blue Dot –offshore substation)
Establishing number and location of offshore platforms
The traditional voltage for interconnecting offshore wind turbines in the UK is 33kV however due to
the power capacities accumulated in each Round 3 wind farm and the distance from shore it is not
possible for the power to be transmitted to the connection points on shore at this voltage. Hence
offshore substations will need to be established within each Round 3 wind farm 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 33kV cable to connect an array can lead to onerous power losses).
For the purposes of this report it was deemed pragmatic to consider the use of 245kV three-core
cross-linked poly-ethylene (XLPE) insulated subsea cable as the immediate transmission medium
from each of the offshore platforms, irrespective of whether it would be AC or DC technology that
would ultimately provide the transmission medium from the entire offshore wind farm or Round 3
zone to the onshore connection point.
To ascertain the power carrying capacity of the 245kV cable, ratings were derived from information
provided by the cable manufacturers [3] and then derated as appropriate for cables situated within
J tubes [4], which would be required to bring the subsea cables from the seabed onto the offshore
platform itself. The resultant cable ratings used in this report are shown in Table 4.
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Cable
Voltage
Cable Type/Size
Current rating
Power rating
Rating after
12% J tube
de-rating
factor
245kV
Copper 1000mm2 c.s.a
825A
350MVA
308MVA
Table 4: Intra array cable ratings
These cable ratings were then applied to each wind farm’s indicative installed capacity to establish
how many platforms would be required for each wind farm and hence how many ‘arrays’ radiating
out from those platforms each wind farm would contain. For the purposes of this report in order to
minimize offshore transmission cable lengths (and hence losses and cost) the number of platforms
was kept to a minimum and each platform was placed on the side of the wind farm orientated to
the likely connection point, (although this would result in larger offshore platforms with a
requirement for sixteen switch panels at 33kV and array cable lengths of up to 13km with minimal
losses at full load). In practice the location and number of the offshore platforms will be dependent
on the capital and operational costs for both the offshore transmission network and the wind farm
cable array, with design parameters optimised for a particular wind farm.
3.3
Connection link technologies, capabilities and limitations
Section 3.1 described how the raw wind farm capacities were arrived at, however due to the large
Round 3 wind farm capacities considered and the distance of some of the wind farms from
potential connection points on the onshore network, the cost of the offshore transmission assets
and therefore their capability will play a significant part in the economic viability of each project.
For this reason a number of connection technologies and their capabilities and limitations were
assessed for this report and each is described briefly below.
3.3.1
AC cables
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 it comes to crossing 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 charging current can be mitigated by connecting reactive compensation at regular intervals
along the cable, however as most of the Round 3 wind farms require long sections of subsea
cable, providing this interstitial reactive compensation would present an added technological and
financial challenge. However it may be possible to connect shunt reactive compensation to the
cable at or close to the transition point from subsea to underground cable. Hence an assessment
of the reduction in effective power carrying capability of the AC cable described in Section 3.2 due
to charging current and resistive (I2R) losses and the effect of adding reactive compensation at
three points along the cable route length was carried out using the PSS/Sincal power system
analysis software. An explanation of the analysis methodology is given in Appendix 2 while the
results of this analysis are shown in Table 5.
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Reactive Power Compensation Optimised
Reactive compensation
Q received (MVAr)
applied (MVAr)
P received (MW)
Length
(km)
no
rpc
50/50
split
0
20
40
60
80
100
120
140
160
180
200
330
329
329
328
327
325
323
321
317
311
303
330
329
329
328
327
326
325
324
322
321
319
S total (MVA)
33/33/
33
split
330
-108
-108
-108
0
0
0
347
347
347
329
75
0.589
-1.429
0
37
26
338
329
329
329
160
-0.558
1.387
0
79
52
329
329
365*
328
247
0.784
0.446
0
120
80
328
328
411
327
339
0.682
-0.149
0
162
108
327
327
471
326
435
-0.808
-0.300
0
205
136
326
326
543
326
537
0.876
0.128
0
247
164
325
326
627
325
646
-0.830
1.315
0
291
192
324
325
721
324
765
-1.249
-0.344
0
335
221
322
324
828
323
896
0.071
-1.217
0
379
250
321
323
949
322
1042
0.800
-0.993
0
424
279
319
322
1085
Table 5: Power Transmission Capability of 1000mm2 subsea cable against route length
33/33/3
3 split
no rpc
50/50
split
33/33/33
split
no
rpc
50/50
split
33/33/33
split
no rpc
50/50
split
*Figures in red indicates where either the MVA or Current rating of the cable is exceeded
Cable Data
operating voltage
offshore:
X
R
C
onshore:
X
R
C
Thermal capacity
1845 Crown Estate Round 3 OWF connection study v1.0 (FINAL).doc
275
kV
0.18
0.023
0.18
ohms/km
ohms/km
uF/km
0.185
0.023
0.185
ohms/km
ohms/km
uF/km
825
A
Values from Electrical Cables handbook &
from ABB XLPE Submarine cable system
handbook
Page 19 of 94
I average (kA)
no
rpc
50/50
split
33/33/33
split
NA
0.709
0.721
0.747
0.785
0.836
0.900
0.978
1.072
1.184
1.317
NA
0.717
0.730
0.745
0.765
0.789
0.814
0.843
0.874
0.907
0.941
NA
0.713
0.718
0.726
0.736
0.748
0.763
0.780
0.799
0.820
0.842
A further challenge posed by long AC cable circuits is the additional demands imposed on the
circuit breakers providing protection and control functions due to the large capacitances created
within the cable, and the attendant cable charging current drawn. Careful selection of circuit
breakers and control equipment is necessary to ensure that integrity of operation can be ensured,
particularly when the long offshore cables are being energised without the wind turbine
transformers in circuit.
For these reasons AC subsea cables have only been considered as a possible connection
technology in this report where the total cable route length is less than 100km.
3.3.2
HVDC
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 4).
Figure 4 Overview of VSC HVDC bipolar transmission for offshore wind farms
©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 ideal for offshore deployment.
However, the power losses arising from the increased switching frequency of the devices used
within the VSC technology and the power ratings of the technology currently available mean that,
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at very high power transfer levels, CSC technology with some form of commutation support could
become an option for offshore deployment.
3.3.2.1
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 planned 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 drawn by the converter and to provide the required
reactive power to the 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 UK). If
connected to a weak network, commutation of the thyristors may not occur correctly and cause
instability in the system. To use CSC HVDC technology to connect the Round 3 offshore wind
farms may require additional compensation in the form of synchronous compensators to provide a
strong voltage source to commutate the DC current.
3.3.2.2
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 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 rapidly (up to 2000 times
per second) to modulate a voltage waveform.
At present the power handling capability of the largest available VSC HVDC converter module is
1000MW at ±300kV, however capabilities of 1110MW may well be possible in the immediate future
for single converter XLPE insulated bipole pairs operating at ±300kV, and 2000MW to 2200 MW
for dual converter Mass Impregnated bipole pairs operating at ±500kV.
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Mass Impregnated cables have been the traditional medium for transmission in DC systems until
now. 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 rely on extruded poly-ethylene as the insulation medium for the
conductors. These cables are easier to manufacture and correspondingly cheaper than their MI
equivalent, however currently can only operate at voltages up to 300kV which limits possible power
flow.
Figure 5(a) Mass Impregnated 500kV DC cable
Figure 5(b) XLPE 150kV DC cable
©Prysmian Cables
©Prysmian Cables
Figure 6: HVDC VSC configuration
©ABB
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Figure 7: HVDC Dual Converter pair redundant bipole with metallic return path configuration
©ABB
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 the DC system.
Although possible with CSC, control of the power flows in a multi terminal network is more onerous
than with VSC due to the ability to minutely control the firing of the power electronic devices within
the VSC converter.
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3.3.3
Gas Insulated Transmission Lines
Traditional HVAC subsea cables and HVDC subsea bipole technologies are well understood and
widely applied, albeit maybe not at the power capacities required for Round 3. However, due to the
large connection capacity required and the distance offshore, other transmission technologies may
become viable alternatives.
One such technology is Gas Insulated transmission Lines or GIL. Gas insulated lines, as the name
suggests encompass a high voltage AC conductor within a sealed aluminium pipeline which is
filled with a SulphurHexafluoride (SF6)/Nitrogen mix as an insulating medium (see Figure 8).
Figure 8: Cross section through a GIL showing conductor tube, enclosure and insulators
© Siemens Power Transmission & Distribution
The advantage of this technology is that it allows very high power transfers of up to 3000MW per
three phase system [5], without the disadvantage of the charging current required by traditional AC
cables, and can be installed underground, above ground or in tunnels (See Figure 9). Hence this
technology is ideal for the bulk transfer of power over large distances where overhead lines are
impractical, and has obvious advantages for connecting groups of large offshore wind farms.
Figure 9: GIL directly buried and in tunnel arrangement
© Siemens Power Transmission & Distribution
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To date the longest length of GIL installed is the 4.5km at the Tehri Hydro Project in India [6],
however the European Commission of Trans European Networks for Electricity is sponsoring a
project looking at the use of GIL in the North Sea, focussing primarily on the installation techniques
required, which are similar to those applied by the oil and gas industry to install the thousands of
kilometres of subsea pipelines used in that field. The use of GIL to provide power corridors to
group the output from a number of offshore wind farms is attracting particular interest in Germany
because it reduces the impact on the environmentally sensitive areas of that country’s North Sea
coast which has a parallel with the environmentally sensitive areas such as the Wash and the
Humber estuary in the UK.
The disadvantages of GIL for the purposes of Round 3, is that it is as yet an untried technology in
the subsea environment, and over these distances, that the costs may be excessive compared to
the more traditional technologies (see Section 6), and that the power capacity of the individual lines
may be limited by the largest loss of power infeed that can be accommodated by the system
operator, which is stipulated in the GB Security and Quality of Supply Standards (GB SQSS) (see
Section 3.4).
Some environmental concerns also exist over the increased use of the inorganic compound SF6,
often used in the electricity industry for its dielectric properties, which has been shown to be a
greenhouse gas with approximately 22,000 times the potency of carbon dioxide (CO2) if released
into the atmosphere. This would also have to be taken into account when assessing the suitability
of this technology for the connection of offshore wind generation, as existing onshore transmission
owners have policies of minimising the use of this gas.
However the GIL technology is based on seamless welding with practically zero losses (<0.05%
per year) of the insulating gas which is made up of a 20% SF6/ 80% Nitrogen mix. In case of
external damage only one section of one phase (i.e. one gas compartment) is affected, which will
limit any gas release. The length of these gas compartments ranges from 20m to 1200m
depending on requirements, and due to the low losses require no gas refilling over the project
lifetime.
3.3.4
Superconductors
Another technology that is being introduced on a small scale to Power Networks around the world
is superconductor power cables. Like GIL, high temperature superconductor wires (HTS) offer
three to five times the capacity of traditional DC cables and ten times that of traditional AC cables
[7]
Each HTS wire can conduct 150 times the electrical current of copper of the same dimensions.
Many of these wires are then wound together to form a power cable capable of carrying up to
574MVA at 138kV. To dissipate the heat generated within the cable (and in the second generation
HTS cables) to provide insulation properties, liquid nitrogen is pumped between the various layers
of the cable (see Figure 10). Hence any HTS system would require coolant pumping stations at
periodic intervals along the cable route.
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Figure 10: Cross section of HTS ‘cold’ dielectric cable with copper core to carry fault currents
© American Superconductor
As with the GIL systems the advantage of using HTS is to minimise the offshore transmission
system required for a given power transfer, however again as with GIL, the longest HTS system in
operation at present (with the Long Island Power Authority in the US) is only half a mile long, the
technology has never been used in an offshore environment, and due to the requirement for
coolant pumping stations, the costs may be excessive offshore compared to the more traditional
technologies. However HTS technology could be considered for some of the onshore connection
routes as a viable alternative to multiple AC or even DC cables.
3.4
Establishing offshore redundancy, security & quality of supply criteria
One of the key criteria that any connection design must consider is the trade off between the initial
capital investment, and the opportunity cost of lost energy due to losses within the system,
unavailability due to scheduled maintenance, and unavailability due to faults (which can be of
particular concern in the marine environment due to the difficulty in finding the faulted section and
repairing it within a benign weather/tide window). This may result in some form of redundancy,
either partial or full, being built into the design, which will add to the capital cost, but potentially
reduce the operating costs.
Redundancy will also be of interest to the respective onshore system operators, as they will need
to cater for the loss of power infeed caused by sections of the offshore network tripping out under
fault conditions.
A great deal of work has gone into assessing the level of redundancy required for offshore
transmission assets. In developing these deterministic standards to facilitate a regulatory regime
for offshore transmission, the Centre for Sustainable Electricity and Distributed Generation (SEDG)
were employed, on behalf of BERR (now DECC) to undertake cost benefit analysis that would
underpin these standards. A report entitled “Cost benefit methodology for optimal design of
offshore transmission systems” [8] has been published outlining the input assumptions, models
used and results obtained from this work. The results arising out of this work informed the
recommendations for an offshore security standard published by National Grid and used to
develop draft text for new, offshore sections of the standard, which is currently under consultation.
It is from the recommendations of this report that the designs within this study have been derived,
although with some important deviations as explained in Table 5 below.
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SEDG
Results
GB Offshore SQSS
Recommendation [9]
Criteria used for this
report
Platform export Capacity
About 95% of installed
capacity
100% of installed
capacity
90%+ of installed
capacity
Transformer redundancy
50%
50%
50%
HV / LV terminals
connected
-
Yes
Yes
Platform export capacity
following outage of one
AC circuit
-
Minimum 50%
Minimum 50%
No redundancy
No redundancy
No redundancy
1000MW
1000MW
1110MW*
100%
90%+
1320MW
1320MW
1800MW**
50%
50%
50%
OFFSHORE PLATFORM
DC offshore platform
Maximum Power infeed
loss following outage of
single DC converter
OFFSHORE CABLE NETWORK
Network capacity
95% of installed capacity
for geographically small
wind farms
90% of installed capacity
for geographically large
wind farms
Maximum Power infeed
loss for loss of single
offshore transmission
cable
ONSHORE SUBSTATION
Transformer redundancy
Table 6: Redundancy Criteria used for this report
* The 1110MW DC converter power infeed loss is set by the maximum MVA rating of the HVDC voltage
source converter stations as indicated by the manufacturers.
**An 1800MW infrequent infeed loss limit (as opposed to the current 1320MW) is representative of the level
of response and reserve that may be required to be held by the GB system operator in order to
accommodate the next generation of nuclear power stations. This requirement for an increased level of
response and reserve is currently under review. Although National Grid sees no technical barrier to its
implementation, the economic implications are being thoroughly investigated and consulted upon before a
final decision is made.
It is also important to note that in the joint Ofgem/BERR Regulatory Policy Update dated 13th June,
2008 [16], the need to “Analyse and define the basis for an offshore security standard that can
cater for generation projects of the size and location of Round 3 projects” was highlighted due to
the limited scope of previous work. This further analysis, which forms part of the wider
Fundamental Review of the GBSQSS currently underway [15], will seek to update previous work to
ensure that it is fit for purpose and applicable to all projects that could reasonably be foreseen to
arise in the future. This work, being undertaken by the three onshore transmission owners and
supported by the SEDG Centre, has the potential to impact the design of the offshore transmission
system (i.e. assets operated at 132kV and above) used in this analysis.
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3.5
Tailoring Installed Capacity to Connection Capacity
The methodology described in Section 3.1 was used to establish the power capacity of each of the
wind farms, adjusted to meet the zonal indicative connection capacities. However due to the
capacities accumulated in each Round 3 wind farm and the distance from shore, the cost of the
offshore transmission assets themselves will form a significant element within the overall capital
cost of the wind farm, such that there will be a significant incentive to fully utilize the capacity of the
offshore transmission assets as far as possible. Due to the variable nature of the wind resource,
unavailability of individual wind turbines due to maintenance, and power losses in the array
cabling, a connection design that was capable of transmitting the output from the entire installed
capacity of the wind farm would only be fully utilized for a small percentage of the wind farms
lifetime, hence an attempt was made at a high level within the auspices of this study to ascertain
what the optimal installed generation capacity would be for a given connection capacity.
The results of this analysis are given in Appendix 1, however in summary for an offshore wind farm
in the North Sea with an average wind speed on the Dogger Bank of 8.8m/s [10] and an availability
of 90% (Note. The Round 1 offshore wind farm at North Hoyle had an average availability of 87.4%
in its third full year of operation (2006-07) [11]), the optimised installed capacity derived was 112%
of connection capacity. This compares well with the results of the similar analysis carried out by
SEDG which arrived at an indicative range of 105% to 111% depending on the geographical area,
(and hence wind diversification), of the wind farm in question [8].
This Figure of 112% installed capacity coupled with the technology ratings stated in Sections 3.2
and 3.3, the zonal indicative connection capacities from The Crown Estate, and the raw wind farm
capacities derived in Section 3.1 were used to establish the wind farm capacities listed in Table7
on which the subsequent offshore and onshore designs were based.
Round 3 Development Zone
Round 3 Wind farm
Indicative (Installed) Zonal
Connection Capacity
Polygon Installed capacity
(defined by letter)
Moray Firth
(MW)
500 (500)
C
Firth of Forth
500
100 x 5MW
500 (500)
G
Dogger Bank
Number of Wind Turbines
500
100 x 5MW
9000 (9907.5)
H1
1237.5
165 x 7.5MW
H2
1237.5
165 x 7.5MW
H3
1237.5
165 x 7.5MW
H4
1237.5
165 x 7.5MW
H5
1237.5
165 x 7.5MW
I1
1240
248 x 5MW
I2
1240
248 x 5MW
J
1240
248 x 5MW
Hornsea
3000 (2477.5)
M
1237.5
165 x 7.5MW
N
1240
248 x 5MW
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Round 3 Development Zone
Round 3 Wind farm
Indicative (Installed) Zonal
Connection Capacity
Polygon Installed capacity
(defined by letter)
Norfolk
Number of Wind Turbines
(MW)
5000 (4955)
T
1240
248 x 5MW
U
1237.5
165 x 7.5MW
Z1
1237.5
165 x 7.5MW
Z2
1240
248 x 5MW
Hastings
500 (500)
AA
500
West Isle of Wight
500 (500)
DA
500
Bristol Channel
100 x 5MW
100 x 5MW
1500 (1500)
EA (ac)
1500
200 x 5MW
EA (dc)
1237.5
165 x 7.5MW
Irish Sea
5,000 (4,955)
IA
1237.5
165 x 7.5MW
JA
1237.5
165 x 7.5MW
LA
1240
248 x 5MW
NA
1240
248 x 5MW
TOTAL
25,500 (25,795)
Table 7 Round 3 Polygon Installed Capacities
3.6
Assessing landfall points, onshore cable routes & land availability
As part of finalising the onshore network points of connection, desktop assessments using
Ordnance Survey maps and satellite photography were made to ensure that there was sufficient
land area around the onshore connection points to potentially accommodate the new substations
or substation extensions and equipment, such as HVDC converter stations, necessary to facilitate
the offshore network. This method was also used to identify potential landfall locations for the
transition from the offshore subsea cable to the onshore underground cable, and then establish a
possible onshore cable route from these landfall points to the onshore network connection points.
Due to the differential in price between subsea and underground high voltage AC cables (in the
order of 10%-20%), the onshore cable route length was minimized as far as possible, however
where required, the cable routes were chosen to follow existing roads or disused railway beds in
order to limit the elevation changes over the cable route, and also, as far as possible, avoid any
obstacles such as river crossings that may require directional drilling.
3.7
Assessing offshore cable routes
Offshore, the most direct cable routes were established 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
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was unavoidable, the cost of these crossings (using concrete mattresses and rock dumping etc)
has been included in the overall costings. In order to minimize the cable route lengths onshore,
wherever possible the subsea cable has been extended up through river estuaries before coming
ashore. Due to the additional installation and cable protection requirements that may be required
as a result, particularly in areas where there is heavy river traffic and existing pipeline and cable
crossings such as the Humber, the potential cost saving in using subsea cables may be eliminated
although again this will need to be assessed on a detailed case by case basis, which is outside the
scope of this report.
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4
Offshore Cost Methodology
In order to provide as accurate a cost model as possible a number of high voltage power
equipment manufacturers and installers were consulted for the current costs of the equipment that
would be required to realize the offshore connection designs described in this report.
To that end information was very helpfully supplied by Siemens, ABB, Areva, Prysmian Cables,
American Superconductor, ETA ltd, Senergy, and National Grid to facilitate this report.
Due to the impact on cost of the actual installation conditions specific to the site, and 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 combined with equipment cost
information in the public domain such as that from the SEDG report [8] and an average price taken
for each equipment element required for the offshore connection designs. It was these average
equipment prices that were then used to cost the connection designs proposed.
The offshore connection designs were costed from the HV transformers on the offshore wind farm
platforms to the busbar clamps at the onshore substation. These points are also referred to as the
Grid Entry Point and Onshore Interface Point, respectively, and together would form the extent of
the offshore transmission system under the proposed offshore regulatory regime. Note that in
some of the connection solutions proposed in this report, the offshore transmission system extends
to more distant connection points onshore than those closest to the wind farm. This is because the
designs proposed balance the need for offshore and onshore reinforcement in order to achieve the
optimal solution. The connection design cost inclusions and exclusions are listed in Table8 below.
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Offshore Connection Design
Cost Exclusions
Cost Inclusions
•
400kV double busbar AIS or GIS
transformer /feeder bays
•
33kV offshore switchboards
•
•
Wind farm 33kV array cabling
HVDC converter station onshore
•
•
Onshore reactive compensation
Offshore reactive compensation for array
cabling
•
Wind farm substation compound land
cost
•
Wind Turbines and installation
•
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
•
5% contingency
Table 8 Offshore connection design cost inclusions
Each connection design was based on a generic 245/33kV offshore platform design, HVDC
converter arrangement, and onshore 400kV transformer feeder bay arrangement which are detailed
in Senergy Econnect drawing numbers 1845 009, 010, and 011 below. Drawing 009 represents the
HVAC design used for the 500MW wind farms, drawing 011 the HVAC design for the 1200MW wind
farms and drawing 010 the HVDC design for the 1200MW wind farms. Note that the equipment
ratings shown in these drawings will change depending on the specific connection design.
The cost of land required for converter stations and wind farm substation compounds will vary
substantially depending on the location. However, for the purposes of this report an average land
cost of £75k per hectare for brown field sites and £150k per hectare for green field sites was used in
line with National Grid estimates.
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.
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The amount of reactive compensation included at both the offshore platform and onshore connection
point have been derived from the results in Table4. The reactive compensation applied is solely to
compensate for the capacitive charging current of the transmission cable and to maintain a unity
power factor at the receiving end, and does not allow for any compensation of the wind farm array
cabling. Note that the revised drafting of the System Operator/Transmission Owner Code (STC) to
facilitate the proposed offshore regulatory regime includes an obligation on the owner of the offshore
transmission assets to provide a reactive capability of 0.95 lead to 0.95 lag at the interface point with
the onshore transmission network. The additional static and dynamic reactive compensation
equipment required to meet this obligation has not been costed as part of this report as each wind
farm could require a bespoke solution, however this could have a significant cost and land
requirement implication for those zones connecting using AC technology.
Initially each wind farm connection design was costed according to the appropriate technology used,
however where a connection design could feasibly use either AC or DC technologies, both
connection designs have been costed for comparison. In the same way where there is more than
one technology that could be used to connect multiple wind farms within a zone to an onshore
connection point, both options have been costed where possible to provide a comparison.
As regards the switchbay technology used for the cost estimates onshore, Gas Insulated Switchgear
(GIS) was used where the connecting substation was 5km or less from the coast, and Air Insulated
Switchgear (AIS) used for all other cases. Offshore all the switchgear used was GIS.
A summary of the costs for each wind farm connection design is provided in Sections 6&7 of this
report with the detailed cost breakdowns forming the bulk of the appendices to this report.
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5
Onshore Design
The onshore electricity transmission system, as it exists today, has been built up over a period of
time around the prevailing generation and demand background. It takes the electricity produced by
generators across Great Britain and transmits it over large distances to points where the lower
voltage, distribution networks take it further to the actual demand consumers. The transmission
system is designed to ensure that electricity demand can be supplied at times of peak load and to
facilitate competition in the electricity market in an economic and efficient manner.
5.1
Assessing requirements for additional capacity on the onshore
transmission system
In assessing the need for additional capacity on the transmission system, transmission owners
(including National Grid Electricity Transmission in England and Wales) are required by their
transmission licences to design the system to accommodate peak demand levels according to the
minimum, deterministic criteria outlined in the GB System Security and Quality of Supply Standards
(GB SQSS) [12] complemented with a limited amount of additional cost benefit analysis for year
round conditions. The total nominal output capacity of generating plant connected to the system at
any given time exceeds the forecast peak demand, since a margin is required to cover for inevitable
plant breakdowns and forecasting errors: in planning timescales there is always some uncertainty
over the distribution of demand and the generators that will actually run to supply it. The GB SQSS
sets out criteria for designing the system infrastructure (The Main Interconnected Transmission
System, or “MITS”) in order to address these uncertainties.
Currently, the generation fleet in Great Britain is largely comprised of conventional coal, gas and
nuclear units with a peak-demand availability of > 80%, thus limiting the possible range of input
assumptions to the analysis. Unless restricted by breakdowns, conventional generators normally run
at, or close to, their maximum output since this is their most efficient mode of operation. Renewable
generation generally exploits variable energy sources such as wind or solar energy. Wind turbines
will seldom operate at full output individually, and even more rarely collectively. An economic and
efficient onshore transmission system that incorporates substantial renewable generation will have to
be designed to handle the variability of wind power together with its interactions with conventional
plant availability and demand uncertainties.
Over a year, the average output of offshore wind generators can be expected to be of the order of 30
– 40% of their rated output, but wide variations will occur during the year. The network must be
designed so that power can be exported from areas with wind generation when wind output is high,
whilst allowing sufficient power to be imported to areas with wind generators when their output is low.
To a large degree, the output from wind generation will share transmission capacity with
conventional generation. This is particularly the case where the location and distribution of wind
generation is similar to that of conventional plant in a given area and where the spread in marginal
cost between wind and conventional generation is relatively large (i.e. areas where coal and gas
generation are located with wind). The sharing of existing capacity will not occur to the same degree
in areas of the system where this spread in marginal cost is much less (i.e. areas where nuclear
generation is located with wind).
The criteria in the current GB SQSS for design of the MITS are suitable for a system comprised of
conventional generation with only a small amount of renewables and so need to be developed
further to encompass large volumes of renewable generation. This has been the subject of much
recent work in the UK which continues under the auspices of the Fundamental Review of the GB
SQSS which is currently being directed by the GB-SQSS Review Group [13]. Modified standards
arising from that Review will not come into force before 2010, so the analysis for this report has been
done using the same interim methodology used for the 2008 Seven Year Statement, and outlined in
Chapter 7 of that document [14].
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In addition to criteria for design of the MITS, the GB SQSS also specifies requirements for the local
connections to power stations. These must be designed to carry 100% of the output of a power
station minus any local demand. These criteria have been applied in this project to determine the
local transmission capacity needed at each point of connection to the GB Transmission System.
5.2
Scenario – Background assumptions on generation and demand
It is clear from Section 5.1, above, that the generation and demand pattern assumed in assessing
additional capacity requirements for the onshore transmission system can have a large impact on the
outcome of the assessment. In addition, the further one moves towards the future, the more
uncertain the likely generation and demand pattern becomes. Therefore it is general practice to
choose a scenario that represents one possible future outcome for analysis, as well as to investigate
sensitivities around this scenario to identify the effects of different possible future outcomes.
The proportion of generation by fuel type within the scenario utilised for this study is illustrated in
Figure 11, below.
Figure 11: Proportion of Generation by Fuel Type in Base Scenario
From Figure 11, it is clear that the scenario used for this study is characterised by a large proportion
of generation from renewable sources (approx. 40%) and that the bulk of this is provided by offshore
wind. Also of note is that the proportion of electricity generated from coal is assumed to reduce
significantly with new ‘Clean Coal’ technologies replacing all existing coal generators on the system
to form only a small portion of the total. Gas fired generation will likely play a large role in a world
with large volumes of renewables due to its flexibility and efficiency. Many of the existing nuclear
stations have come off of the system and the scenario has assumed that only two new units will be
constructed within the timescales considered. Some of the main sensitivities discussed in this report
will be around the possibility of further nuclear connections, where this could affect the solution for
the connection of Round 3 offshore wind.
In this scenario, all onshore, transmission connected wind was assumed to connect in Scotland.
Currently there is insufficient transmission system capacity to facilitate this level of generation in
Scotland. The Electricity Networks Strategy Group (ENSG) has instigated a collaborative study
between the three onshore transmission owners that will seek to ascertain the reinforcements
required to facilitate the 2020 targets. Two potential reinforcement options being investigated are
incremental upgrades to the onshore transmission system and offshore HVDC links which will bypass large, congested portions of the onshore network. This scenario has assumed that two HVDC
links will be established; one on the West coast from Hunterston to Deeside and one on the East
coast from Peterhead to Hawthorne Pit. The collaborative study is still ongoing, so this work has not
yet concluded. However, in order to facilitate this investigation for potential Round 3 wind projects,
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this was deemed a reasonable assumption. The scenarios used for this study and that of the
collaborative study are broadly consistent, given the range of sensitivities considered.
Projected peak demand levels also play an important role in the scenario assumptions. In the base
scenario demand is expected to decrease by approximately 8% to 56.3GW, reflecting the potential
impact of energy saving measures and increasing contribution of small, embedded generation
projects.
5.3
Onshore Transmission Requirements: Methodologies for Costing and
Option Analysis
As outlined above, the final choice of onshore connection points for the indicative Round 3 offshore
development zones was determined by finding an economic balance between the offshore and
onshore reinforcement required, including the cost of both local (substation and circuits) and wider
(Main Interconnected Transmission System (MITS)) onshore reinforcements against the scenario.
The onshore transmission system refers to the entire network beyond the onshore interface point
forming the boundary between the onshore and offshore transmission systems.
5.4
Cost Basis
Costs for various components of the overall design have been based on:
•
Offshore and onshore AC & DC cables – Data provided by manufacturers through SenergyEconnect, as outlined in Section 5. For onshore AC cables these have included comparisons
with National Grid’s cost estimating system
•
Onshore substation work – Budgeted from either site specific estimates for revisions to
existing installations, using National Grid’s cost estimating database, or using ‘generic’
estimates around a range of basic transmission network elements – e.g. for new substations
a series of standard arrangements have been assumed and cost estimates created for these.
As such, costs may vary when local requirements at individual locations are taken into
account
•
At each of the National Grid substations an evaluation of land requirements and availability
was undertaken to determine if additional land and planning consents would be necessary.
Where appropriate, estimates for undertaking this work have been included
•
New overhead lines – Where these are proposed, a generic cost estimate has been used,
based on ‘standard’ circumstances- i.e. foundations, access, and routing (i.e. assuming
reasonable sections of overhead line are in straight lines and do not require significant
quantities of angle towers for changes of direction)
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Onshore Transmission System Design Cost Inclusions
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Busbar extensions for new connection bays
Busbar protection, for new connection bays
Substation extensions, including fencing, surfacing, drainage
and internal access roads
Land purchase
Surveys and environmental impact assessments
An allowance for site screening
Obtaining planning permission, or overhead line consent for the
National Grid works
Substation reconfiguration costs
Additional circuit bays for infrastructure modifications
Overhead line diversions into new substations
Where combined with a DNO connection all costs associated
with providing this, including SGT’s and LV connections.
All civil works for National Grid assets
Protection and Control changes, including remote ends of
modified circuits
Overhead line construction or re-stringing
For new sites/routes an allowance for siting and routeing studies
and consultation
Works award process costs
•
•
•
•
Cost
Exclusions
System access
constraints
Circuit outage – system
uplift costs
Consent /planning
permission mitigation
Third Party Costs
Table 9 Basis of Onshore Transmission Costs
NB: All costs are based on 2008 price levels
Where new overhead line (OHL) routes are proposed route lengths have been estimated assuming
that routes will avoid environmentally and visually important areas. In estimating the cost of these
circuits no allowance has been made for the potential need to install sections as underground cable,
apart from some line entries to substations or water crossings where it is apparent that this will be
required. The overall cost of any new OHL routes could increase if sections of underground cable
are required.
The major new 400kV infrastructure overhead line routes considered have all been estimated on a
‘stand-alone’ cost. The possibility remains, that for certain sections mitigation measures may be
identified where adopting, and rebuilding an existing 132kV route owned by a Distribution Network
Operator (DNO), may be appropriate. No allowance has been made for this, or for the creation of any
additional DNO supply points that may arise as a consequence.
The design and costing process has considered a “total solution” capable of handling the entire 25
GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms in
a zone are required and that the overall onshore transmission system changes will all occur in a
coordinated manner at any one location. Should piecemeal developments be undertaken, wind farmby-wind farm, and/or wind generation capacity change incrementally over a period of years, the
staggered timing of the works would result in multiple site/circuit extensions and this will increase the
overall onshore costs and environmental impact. In order to avoid this extensive stakeholder
engagement, coordination and collaboration is required.
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5.5
Option Analysis
In order to identify and cost the onshore connections and transmission reinforcements, three
approaches to system design were considered:
•
Extending the offshore cables inland to existing onshore transmission sites;
•
Extending the GB Transmission System to new connection substations at the coast;
•
Hybrids of the above approaches
An examination of the Round 3 zones show that they fall into two broad categories:
Zones with only one or two wind farms and relatively small overall capacities (1500 MW or
less)
For these zones, typified by Hastings or West Isle of Wight, major reinforcements to the onshore
transmission system were not required against the scenario, apart from extensions to existing
substations or the establishment of new substations at the onshore interface point. The design
process optimised the costs of cabling from a landing point to an existing substation, to a new
substation on an existing transmission route, or to a new substation close to the coast, with the main
interconnected transmission system extended to it. The savings in cable costs due to connecting to a
new, rather than an existing substation outweighed the cost of the new substation in some instances.
Zones with several wind farms and larger capacities (approx. 3000 – 11000 MW)
For these zones – Irish Sea, Dogger Bank, Hornsea, and Norfolk – the approach was similar to that
used for the smaller zones but the essential difference was that the larger power injection
concentrated in one area of the system meant that transmission network reinforcement would be
necessary. The design optimisation therefore included costs for reinforcing the main interconnected
transmission system as well as the cost of simply connecting the offshore wind to one or more grid
substations.
The overall system changes required for these larger zones are such that a wind farm-by wind farm
breakdown is misleading as the costs are driven by the totality of the installed wind generation, and
cannot be itemised to individual wind farms. Put another way, each individual wind farm might
require little or no reinforcement, but in combination they do. Solutions are therefore presented for
complete zones.
5.6
Scottish System Area
The same approach was taken with regard to the zones located closest to the Scottish Transmission
Owner sites. Working from published network data, high level evaluations were made of possible
connection options.
The costs estimates used have been based on an average of similar works proposed for the National
Grid substation and overhead line works, and would require verification from the relevant
Transmission Owner. The connection options identified for these areas are therefore more prone to
revisions than those proposed for England and Wales.
6
Overall Design Options and Potential Zonal Solutions
The various options considered, high-level design considerations and potential zonal transmission
network solutions are summarised below. These are presented against the input assumptions of the
scenario, taking into account relevant sensitivities and a background of general reinforcements which
are assumed to have already been completed within the timescales analysed.
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6.1
Moray Firth
Onshore Transmission
OWF
Option
1
2
0.5GW AC
to new
substation
C
0.5GW AC
to Keith
C
Offshore
Transmission
£178m
Substation
Extension
Network
Reinforcement
£15*m
Total
£193m
subject to
collaborative
TO study
outcome
£256m
£3*m
£259m
Comments
- indicative
onshore costs
- based on
England &
Wales average
- indicative
onshore costs
- based on
England &
Wales average
Table 10 : Connection cost for Moray Firth Zone
* It is important to note that Scottish Transmission owners have not been consulted in putting together the onshore
transmission costs and that these were compiled on the basis of average costs in England and Wales. This portion of the
costs could change significantly as a result.
Figure 12: Moray Firth zone connection overview
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6.1.1
Offshore connection
Due to the nominal capacity of the offshore wind farm (OWF) located in the Moray Firth and the
distance to the potential connection points a HVDC connection solution was discounted for economic
reasons. Instead an HVAC solution has been proposed consisting of two offshore 33/245kV
substations interconnected with a single three core 245kV cable, and each with a single three core
245kV shorelink cable to transmit the power accumulated from the wind farm to a transition pit
located at the landing point onshore. From this transition pit six single core 245kV cables have been
routed to the potential connection point at Keith 275kV substation. The onshore cable route follows
the road network as much as possible however there are a number of obstacles that would need to
be crossed along the proposed route. The estimated cost for directional drilling under these
obstacles has been included as part of the overall offshore connection cost estimate. Due to the total
HVAC cable length of this connection, a significant amount of reactive compensation is required to
maintain adequate power transfer levels. This reactive compensation has been located both on the
offshore substations and in an onshore substation compound adjacent to Keith substation along with
the associated switchgear and step up transformers which form part of the offshore transmission
assets. Both the offshore and onshore substations have been designed to comply with the offshore
SQSS proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect
drawing 1845 009 (p34). It has been assumed that a two switchbay extension to Keith 275kV
substation would be required to connect the Moray Firth OWF however this would need to be
confirmed with the onshore transmission asset owner.
6.1.2
Offshore connection alternatives
The alternative connection solution for the Moray Firth OWF follows the same offshore connection
route and design but connects to a new 275kV substation a couple of kilometres from the landing
point. As the assets from this point onward would form part of the onshore transmission network, this
option is discussed in more detail in Section 6.1.3.
6.1.3
Onshore reinforcement
Currently, the onshore transmission system is unable to transmit the electricity generated by the
large volumes of renewable generation expected to arise in Scotland down into England where the
majority of demand for electricity is located. The original ‘Renewable Energy Transmission Study’
(RETS) and ‘RETS revisited’ undertaken in 2003 and 2005 respectively, did not envisage the 6 to
11GW of renewable generation now considered likely. Therefore a further collaborative study is
underway between the three onshore transmission owners; National Grid Electricity Transmission
(NGET), Scottish Power Transmission Ltd. (SPT) and Scottish Hydro Electric Transmission Ltd.
(SHETL) under the Electricity Networks Strategy Group (ENSG), to develop the transmission system
in order to facilitate the levels of generation assumed to be required to meet 2020 renewable targets.
The study underpinning this document has not sought to pre-empt the outcome of the
aforementioned collaboration and has made the assumption that the necessary reinforcements from
Scotland into England are already in place. The impact of the need for these reinforcements on the
connection of further rounds of wind leasing is predominately limited to those wishing to connect
offshore in Scotland, such as the Moray Firth, north of this critically congested part of the network.
The alternative connection option relies on potentially adopting an existing 132kV overhead line that
runs from Keith towards the coast, upgrading this line to 275kV and establishing a new 275kV
substation at the coast. The cost of this new substation has been included in Table9, but the cost of
the line upgrade and associated distribution network works has not for the reasons identified above.
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6.2
Firth of Forth
Onshore Transmission
Option
1
0.5GW
AC to
Torness
2
0.5GW
DC tied
into VSC
1.1 GW
East
Coast
link
OWF
G
Offshore
Transmission
£135m
Substation
Extension
Network
Reinforcement
£15m
Total
£150m
subject to
collaborative TO
study outcome
G
£165m
n/a
£165m
Comments
- indicative
onshore costs
- based on
England &
Wales average
- HVDC
interconnection
assumed
- Control system
technical issues
Table 11: Connection cost for Firth of Forth Zone
* It is important to note that Scottish Transmission owners have not been consulted in putting together the
onshore transmission costs and that these were compiled on the basis of average costs in England and Wales.
This portion of the costs could change significantly as a result.
Figure 13: Firth of Forth zone connection overview
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6.2.1
Offshore connection
Again due to the nominal capacity of the offshore wind farm (OWF) located in the Firth of Forth and
the distance to the potential connection points a HVAC solution has been proposed consisting of two
offshore 33/245kV substations interconnected with a single three core 245kV cable, and each with a
single three core 245kV shorelink cable to transmit the power accumulated from the wind farm to a
landing point onshore. As the proposed connection point at Torness 400kV substation is on the
coast, the design assumes that the subsea cable will be brought into the substation cable sealing
ends, with no transition to single core underground cable.
Again the necessary reactive compensation has been located both on the offshore substations and
in an onshore substation compound adjacent to Torness substation along with the associated
switchgear and step up transformers which form part of the offshore transmission assets ( see
drawing 1845 009 (p34). It has been assumed that a two switchbay extension to Torness 400kV
substation would be required to connect the Firth of Forth OWF however this would need to be
confirmed with the onshore transmission asset owner.
6.2.2
Offshore connection alternatives
The alternative connection solution for the Firth of Forth OWF makes use of a proposal to introduce
an offshore HVDC transmission link between Peterhead and Hawthorn Pit to reinforce the onshore
transmission network and accommodate expected power flows from the generation capacity installed
onshore and offshore in Northern Scotland. The route of this offshore transmission link is likely to
pass very close to the Firth of Forth OWF and hence a 500MW HVDC converter could be connected
to the HVDC transmission link at this point to allow transmission of generation output from the OWF.
This solution relies on the HVDC bipole forming the section from the OWF to Hawthorn Pit being
sufficiently rated to allow transfer of the expected power flow from Peterhead and the output
expected from the OWF coincidentally. The connection design for the OWF relies on two 33/245kV
offshore substations interconnected with a single three core 245kV cable, and each with a single
three core 245kV cable to transmit the power accumulated from the wind farm to an offshore platform
housing the HVDC VSC 500MW converter.
As the East Coast Interconnector assets would effectively form part of the onshore transmission
network, this option is discussed in more detail in Section 6.2.3.
6.2.3
Onshore reinforcement
As highlighted in Section 6.1.3, the study underpinning this document has not sought to pre-empt the
outcome of the transmission owner collaborative study currently underway and has made the
assumption that the necessary reinforcements from Scotland into England are already in place. The
impact of the need for these reinforcements on the connection of further rounds of wind leasing is
predominately limited to those wishing to connect offshore in Scotland, such as the Firth of Forth,
north of this critically congested part of the network.
The main options being considered under this work are incremental upgrades to the onshore
transmission system and offshore HVDC links on the west coast from Hunterston to Deeside and on
the east coast from Peterhead to Hawthorne Pit. This study has considered a scenario where the two
offshore HVDC links are in place. Therefore, sufficient capacity is assumed to exist from Scotland
into England in order to facilitate this investigation.
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6.3
Dogger Bank & Hornsea
Due to the potential connection capacity and distance from shore of the Dogger Bank Zone, there is
much greater potential for optimisation in bringing the wind power onto the onshore transmission
system. Also because the offshore wind farms in the Hornsea zone are likely to connect in the same
area of the network as the Dogger Bank offshore wind farms this initial investigation into a
coordinated approach has assessed transmission network reinforcement requirements for both
zones based on the following approaches:
•
Offshore transmission connections extended inland to existing National Grid substations at
Creyke Beck, Thornton, Drax, Keadby and South Humber Bank
•
Hybrid arrangements combining connections to existing transmission sites at Creyke Beck,
Keadby and Grimsby West and new substations to be established near Killingholme and on
the Lincolnshire coast
Note that in some of the connection solutions proposed in this section, the offshore transmission
system extends to more southerly connection points onshore than those adjacent to the Dogger
Bank zone on the North East coast. This is because the designs proposed balance the need for
offshore and onshore reinforcement in order to achieve the optimal solution. The design issues
associated with each of these options are outlined in Sections 6.3.1.and 6.3.2 and their costs are
summarised in the table 12 below.
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Figure 14: Dogger Bank zone option 1 connection overview
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Figure 15: Dogger Bank zone option 2 connection overview
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Figure 16: Dogger Bank zone option 3 connection overview
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Offshore Transmission
Option
1
DOGGER BANK
2.2GW each:
Drax
Thornton
Creyke Beck
Keadby
HORNSEA
2.2GW at South
Humber Bank
2
DOGGER BANK
2.2 GW at Creyke
Beck
4.4 GW New
substation Near
Killingholme
2.2GW at Keadby
HORNSEA
2.2GW at Grimsby
West
OWF
Connection
Substation
Cost
H1
Thornton
£530m
J
Thornton
£580m
H2
Drax
£576m
H3
Drax
£595m
H4
Creyke
£540m
H5
Creyke
£560m
I1
Keadby
£664m
I2
Keadby
£682m
M
South Humber
£413m
N
South Humber
£437m
H1
Creyke
£511m
J
Creyke
£561m
H2
Keadby
£607m
H3
Keadby
£623m
H4
Killingholme
£568m
H5
Killingholme
£584m
I1
Killingholme
£612m
I2
Killingholme
£630m
M
Grimsby
£413m
N
Grimsby
£438m
Onshore Transmission
Substation
Extension
Cost
Network
Reinforcement
Cost
Comments
£16m
£19m
£14m
£290m
£5,948m
£10m
Major Onshore work
includes:
- New 400kV OHL
Willington to
Chesterfield
- New 400kV OHL
Drax- Keadby (sensitive
to review of GB SQSS)
Maximum offshore costs
due to extent of onshore
cabling to existing sites
£22m
Onshore work includes:
£14m
£10m
£62m
£319m
£5,968m
- 400kV OHL; Grimsby
West to Walpole (or
Bicker Fen)
- 400kV OHL; Creyke
Beck to Drax (sensitive
to review of GB SQSS)
- 400kV OHL; Walpole
(or Bicker Fen) to new
substation north of
Eaton Socon
£16m
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Total
Cost
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Offshore Transmission
Option
3
DOGGER BANK
3.3 GW at Creyke
Beck
3.3 GW at new
substation Near
Killingholme
2.2GW at Keadby
OWF
Connection
Substation
Cost
H1
Creyke
£511m
H3
Creyke
£541m
J
Creyke
£561m
H2
Keadby
£607m
H4
Keadby
£619m
H5
Killingholme
£584m
I1
Killingholme
£612m
I2
HORNSEA
2.2GW at new
substation along
Lincolnshire coast
M
N
Onshore Transmission
Substation
Extension
Cost
Network
Reinforcement
Cost
Comments
£5,918m
- 400kV OHL; Grimsby
West to Walpole (or
Bicker Fen)
- 400kV OHL; Creyke
Beck to Drax
- 400kV OHL; Walpole
(or Bicker Fen) to new
substation north of
Eaton Socon
£17m
£10m
£319m
£52m
Killingholme
£630m
Lincolnshire
£404m
coastal
substation
£23m
Lincolnshire
£428m
coastal
substation
Table 12: Connection cost for Dogger Bank and Hornsea Zones
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Total
Cost
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6.3.1
Offshore connection
The capacity of the Dogger Bank and Hornsea OWF and their distance from the proposed
connection points dictate that a conventional HVAC solution will be impractical and uneconomic and
hence an HVDC solution has been applied in each case. For the reasons mentioned in Section
3.3.2, VSC HVDC technology is ideally suited to applications offshore and it is this technology that
has been used for these connections. Indeed the capacity of the OWF themselves has been tailored
to the maximum power transfer rating (1110MVA) of a single VSC bipole/converter pair indicated by
the manufacturers for this study. As each OWF would fully utilise the available power transfer
capability of its dedicated VSC bipole/converter pair there is no advantage in this primary solution of
interconnecting the OWF offshore, hence each OWF in these two zones is radially connected using
an HVDC bipole arrangement to its onshore connection point as indicated in Table12 with the
offshore (subsea) and onshore (underground) cable costs and obstacle crossings both onshore and
subsea costed separately. Note that the offshore cable routes themselves are designed to avoid
areas allocated for mineral extraction, other wind farms, or concentrations of oil and gas pipelines,
however some pipeline and cable crossings are inevitable, and for some routes numerous, and as
such the cost of these crossings has been included in the cost estimates within the appropriate
connection designs.
There are alternative technologies available which may allow and indeed favour interconnecting the
OWF in these two zones and some of these options are discussed in more detail in Section 6.3.2
Offshore the OWF connection design is based on two 33/245kV offshore substations each consisting
of three 200MVA 33/245kV transformers with associated GIS switchgear. Each offshore AC
substation is interconnected to an HVAC busbar on the offshore platform housing the HVDC VSC
1110MW converter via a pair of three core 245kV cables. Although this design requires an extended
33kV cable array to connect the wind turbines to the offshore substations, it has the advantage of
reducing the number of platforms, transformers and switchgear, and 245kV AC cable length required
offshore, and hence represents significant savings in capital cost. As stated previously an analysis of
the full lifetime capital and operational costs will be required to optimise the overall electrical design
for each specific wind farm; however such an analysis is outside the remit of this report.
The power from the offshore converter is then routed through two HVDC cables (forming a bipole) to
an onshore 1110MVA converter located in a compound adjacent to the National Grid connection
substation where it is converted back from DC to AC for input into the onshore transmission network.
Both the offshore and onshore substations have been designed to comply with the offshore SQSS
proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect
drawings 1845 010 and 011 (p35 &36). It has been assumed that a two switchbay extension will be
required at those connection points that are existing substations to connect the Dogger Bank and
Hornsea OWF in line with the requirement of the offshore SQSS for 50% redundancy in the onshore
transformers. Again where a new double busbar 400kV substation is deemed necessary, two
switchbays per wind farm have been allocated and costed as part of the offshore transmission
assets.
The three connection scenarios identified in Table12 and represented in Figures 14, 15 and 16 have
been determined to illustrate the requirement for onshore transmission network reinforcement
necessary for connection of the Dogger Bank and Hornsea zones (see Section 6.3.3). At each
connection point sufficient land area has been identified (and costed based on a nominal £/per
hectare rate) to locate the onshore HVDC converter stations for each OWF adjacent to the existing
or proposed National Grid substation.
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6.3.2
Offshore connection alternatives
The three offshore connection alternative options described below (and summarised in Table12) are
designed to illustrate alternative technologies that could potentially be used in place of the HVDC
VSC technology used in the primary solutions for the Dogger Bank. The onshore implications of
using these connection alternatives have not been considered.
Option 4 foresees the use of Current Source Converter technology to provide the transmission
medium from the OWF to the onshore connection point. CSC technology combined with Mass
Impregnated HVDC cables (see Section 3.3) allow for much greater power transfer capabilities than
VSC. For example option 4 is based on a dual converter HVDC design operating at +/-500kV utilising
four MI HVDC cables with a common LV return cable. This would give a power transfer capability of
3000MW. However in order to minimise the inter wind farm AC cabling necessary to accumulate this
amount of power at the converter platforms, option 1 foresees the installed wind farm capacity in
polygon I of the Dogger Bank zone being expanded from 2480MW to 3360MW with the
corresponding increase in offshore substations. The disadvantages of using CSC offshore such as
the increased physical converter size, and the requirement to provide a strong voltage source in
order for the converters to operate has been allowed for in the cost estimates. Note that as such
technology has not been used offshore to date, the cost estimates below can only be indicative at
this stage.
Option 5 utilises the GIL technology introduced in Section 3.3.3 to provide a ‘power corridor’ out to
polygon I in the Dogger Bank, in this option with an installed capacity expanded to 3105MW. The
creation of these power corridors utilising GIL technology is one option being considered in Germany
for the connection of their own offshore wind farms in the North Sea. However as yet this technology
has yet to be installed in an offshore/subsea environment and hence the costs provided by the
manufacturer for onshore installation have been extrapolated by Senergy Econnect based on
pipeline and cable laying costs in order to provide the indicative cost estimates in the Table below.
The other issue to note with this option is that it does not comply with the proposed offshore SQSS
as the maximum power infeed loss (2771MW at 400kV) would exceed the 1800MW* limit (*see
Section 3.4).
Option 6 still utilises HVDC VSC technology offshore but recognises that the cable route between the
land fall point on the coast and the connection substation at Drax for the H2 and H3 OWF identified
in Option 1 is extensive. Hence the use of a single HVDC overhead line to transport the bipole
conductors for both OWF on a more direct route from the land fall point to Drax substation may be
considered an economic alternative. The costs for HVDC overhead line used in the cost estimates
below have been derived from a manufacturer’s article in the IEEE Power & Energy magazine [19].
Note that this option would not meet the current onshore GB SQSS criteria for the maximum power
infeed loss (1320MW) for the loss of a double circuit overhead line.
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Offshore Transmission
Option
OWF
4
5
6
DOGGER BANK
I1 & I2 combined and
enlarged to 3360MW
installed and jointly
connected via HVDC CSC
to Killingholme
DOGGER BANK
I1 & I2 combined and
enlarged to 3104MW
installed and jointly
connected via GIL to
Killingholme
DOGGER BANK
H2 & H3
Jointly connected onshore
via HVDC overhead line to
Drax
Connection
Substation
Cost
£M
Cost
per MW
£k
Cost per MW
comparison
£
I1 & I2 to
Killingholme
I1
Killingholme
£2,202m
£655k
£501k
I2
I1 & I2 to
Killingholme
I1
Killingholme
£3,185m
£1,026k
£501k
I2
H2
Drax
£1,076
£434k
H3
H2 & H3 to
Drax
£473k
Table 13: Alternative combination connection costs for Dogger Bank zone
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Figure 17: Dogger Bank Polygon I CSC connection overview
Figure 18: Dogger Bank Polygon I GIL connection overview
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6.3.3
Onshore reinforcement
In all cases, including those where the offshore HVDC links are brought into existing National Grid
substations, reinforcement with new 400 kV lines would be needed to ensure enough local
transmission capacity to carry the full capacity of the wind farms entering the onshore transmission
system at the onshore interface. This is currently a requirement under Section 2 of the GB SQSS.
Additionally, a new 400 kV overhead line route would be required to carry the increased power
transfer southwards from the Yorkshire/Lincolnshire area. This requirement would be driven by the
criteria of Section 4 of the GB SQSS for design of the Main Interconnected Transmission System
(MITS).
The choice of route for this new North to Midlands line depends on the connection points of the
offshore HVDC links. With “inland” connections (Drax, Thornton, Creyke Beck, Keadby and Grimsby
West/South Humber Bank – Option 1, above), the most effective option would be a new 400 kV line
from Chesterfield to Willington, with uprating of the existing 275 kV Brinsworth-Chesterfield circuits to
400 kV. With connections around the Humber Estuary (Creyke Beck, Keadby, Grimsby West and
near Killingholme, or new substations close to the coast – Option 2 and 3, above), a route from
Grimsby through Lincolnshire to Walpole (or Bicker Fen) would be preferred. To be fully effective,
this line would have to be extended westwards from the Walpole (or Bicker Fen) substation to a new
substation to be established on the existing Cottam – Eaton Socon circuits somewhere near
Peterborough. This final section of required overhead line, extending westwards from Walpole (or
Bicker Fen) would link two critical north to south circuits on the east coast and have the added
benefit of providing additional onshore transmission capacity for connections into the East Anglia
region as well as the potential for connecting any future offshore developments further south in the
Wash.
The locations of the potential major reinforcements required against the input assumptions used are
illustrated in Figure 19, below.
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Figure 19: Dogger Bank & Hornsea Local Onshore Transmission Network and Location of Potential Onshore
Transmission Reinforcement
Arrangements that involved extending the transmission system eastwards to the coast
(predominately north of the Humber) to connect all the assumed offshore wind generation in these
zones involve more construction of new 400 kV overhead line routes and substations than the
aforementioned options.
As explained in Section 5, onshore transmission requirements are sensitive to the onshore
generation background as well as to the energy coming ashore from offshore wind. Requirements
may also vary as consequences of the current reviews of the GB-SQSS and transmission access
arrangements. The optimum arrangement found in this investigation with 3.3 GW connected at both
Creyke Beck and a new substation near Killingholme, and 2.2 GW connected at both Keadby and
Grimsby West – may well cease to be the optimum choice if the background assumptions change.
While the costs estimated in this work may be taken as indicative of the likely range of eventual
costs, the connection arrangements eventually used will depend on the conventional generation
projects that may be developed in the Yorkshire/Humber area in parallel with the offshore wind
programme.
As outlined above, a variety of solutions were considered, for the overall connection of 11GW from
the Dogger Bank and Hornsea zones. These options ranged from onshore cabling to a variety of
existing National Grid substations, to providing all new connection points on the Lincolnshire, or
Yorkshire coasts. Overall the most economic solution is presently to undertake a mixture of cabled
connections to existing sites and extending the National Grid MITS.
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The primary solution comprises three 1100MVA connections to be cabled to Creyke Beck and two
1100 MVA connections cabled to Keadby substation. A new 400kV substation is proposed to be
established at the existing Grimsby West substation along with a new 400kV overhead line, or at a
new substation on a new Grimsby West – Walpole 400kV overhead line along the Lincolnshire coast
to accommodate a further two 1100 MW connections,. An additional new 400kV substation to
accommodate three 1100MW connections is proposed south of the existing Killingholme substation,
to provide connections into three existing 400kV overhead line routes.
As mentioned, in addition a new 400kV overhead line is required from Grimsby West to Walpole (or
Bicker Fen) substation, continuing on to a new 400kV substation to be established on the Cottam –
Eaton Socon double circuit and another new 400kV overhead line is required from Creyke Beck to
Drax. The additional cost of this onshore infrastructure is £319m.
All options require the construction of new 400kV overhead lines and substations to provide a
compliant system, with all of the capacity connected. The substation extension and network
reinforcement costs provided above assume that a coordinated approach is taken to the design of
the offshore network. No environmental impact assessments of the reinforcement options have been
undertaken at this stage.
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6.4
Norfolk
For the Norfolk zone transmission system reinforcement requirements were assessed for offshore
transmission connections extending inland to existing National Grid substations such as Norwich,
Sizewell and Rayleigh
Sizewell is a connection point for an existing, advanced gas-cooled reactor (AGR) nuclear generator.
DECC has yet to complete the Strategic Environmental Assessment for nuclear siting, but the
connection of new nuclear units at Sizewell is an option that could be constructed within similar
timescales to that of Round 3 offshore developments. One scenario utilised for this study did not
include nuclear replanting at Sizewell within the assumed timescales. However, British Energy
currently has Bilateral Connection Agreements in place for the connection of two European
Pressurised Water Reactor (EPR) nuclear generators at Sizewell with 1650MW in 2016 and a further
1650MW in 2021. In light of this further assessments were undertaken to consider the infrastructure
to provide sufficient onshore transmission capacity if these additional nuclear units at Sizewell
proceed. The studies also assumed that the existing Sizewell B plant would still be generating as it is
feasible that there will be some parallel running of both Sizewell B and Sizewell C stations for a
period of time before decommissioning of Sizewell B takes place.
Figure 20: Norfolk zone option 1 connection overview
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Figure 21: Norfolk zone option 2 connection overview
The design issues associated with each of these options are outlined in Sections 6.4.1, 6.4.2, and
6.4.3 and their costs are summarised in the Table 14 below.
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Option
Onshore Transmission
Network
Substation
Reinforcement
Extension £M
£M
Offshore Transmission £M
OWF
T
(AC)
Connection
Substation
Sizewell
Total
£M
Cost
£M
Without new nuclear unit at Sizewell
£223m
£30m
1
2.2GW AC
at Norwich
2.2GW AC
at Sizewell
Z2
Sizewell
£436m
£171m
U
(DC)
Norwich
£1,728m
£410m
£7m
Z1
Norwich
Comments
£451m
Major onshore work includes:
- Reconductor of two SizewellBramford 400kV double
circuits,
- New Bramford 400kV
substation
- New 400kV Bramford to
Twinstead double circuit OHL
to create a Pelham-Bramford
double circuit route and
Bramford-Braintree-Rayleigh
overhead line with
reconductoring of BramfordBraintree-Rayleigh OHL
routes.
With new nuclear unit at Sizewell
2
1.1GW
Norwich
1.1GW
Sizewell
2.2GW
Rayleigh
T
(AC)
Sizewell
£223m
£23m
U
(DC)
Norwich
£410m
£4m
£187m
Z1
Rayleigh
£1,990
£573m
£11m
Z2
Rayleigh
£559m
Table 14: Connection costs for Norfolk Zone
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The overall optimum design
proposed for this background
(i.e. with new nuclear at Sizewell)
has sought to minimise onshore
reinforcement requirements to
reduce timescales. However, if
onshore reinforcement where to
begin in advance of financial
commitment from users, it may
be possible for a more economic
solution to be delivered within the
necessary timescales.
6.4.1
Offshore connection
Due to the proximity of the OWF T and U in the Norfolk zone to their respective connection points at
Sizewell and Norwich Main, cost estimates for both an HVAC and HVDC solution were derived.
However due to the their distance offshore, AC solutions for OWF Z1 and Z2 were not deemed
pragmatic and hence only HVDC connection solutions have been assessed for these two wind
farms. As explained in Section 6.4.3, the connection points for OWF Z1 and Z2 and hence their
respective bipole cable route lengths, (which form the bulk of the cost differential between the
offshore costs in option 1 and option 2), have been determined by the presence or not of a new
nuclear unit at Sizewell C.
Offshore the OWF connection designs are based on two 33/245kV offshore substations each
consisting of three 200MVA 33/245kV transformers with associated GIS switchgear. For the HVDC
solutions each offshore AC substation is then interconnected to an HVAC busbar on the offshore
platform housing the HVDC VSC 1110MW converter via a pair of three core 245kV cables.
The power from the offshore converter is then routed through two HVDC cables (forming a bipole) to
an onshore 1110MVA converter located in a compound adjacent to the National Grid connection
substation where it is converted back from DC to AC for input into the onshore transmission network.
Where a new double busbar substation extension to the existing National Grid substation is deemed
necessary, two 400kV switchbays have been allocated and costed as part of the offshore
transmission assets.
The HVAC connection solution utilised for OWF T and U is different. In this design two 245kV three
core cables are taken direct from each offshore substation to the landfall point (i.e. four three core
cables in total). Where required there is a transition at this point from three core subsea cable to
three single core underground cables per circuit (i.e. twelve cables in total) which are then routed to
a 245kV busbar in a compound adjacent to the National Grid substation, the voltage is then stepped
up to 400kV via two 600MVA transformers for input into the National Grid via two GIS or AIS 400kV
double busbar switchbays as appropriate. The cost of crossing both the offshore and onshore
obstacles along these cable routes, the cost of the transition, and the cable joints have all been
allowed for in the cost estimates provided. This design meets the offshore SQSS requirement for
50% redundancy in export capacity from an offshore platform following loss of an AC cable but does
not require the offshore substations to be interconnected. This 1200MW HVAC design is represented
diagrammatically in Senergy Econnect drawing No 1845-011 (p36)
6.4.2
Offshore connection alternatives
As explained in the previous section, alternative connection solutions for wind farms T and U were
costed using HVAC and HVDC technology for comparison purposes. Options 3 and 4 (see Table14)
demonstrate the breakpoint of where HVAC becomes uneconomic and HVDC economic and vice
versa. Because OWF T is relatively close to Sizewell, the extra cost of the two HVDC converters
outweighs the saving in cable cost in using an HVDC solution (two cables for DC as opposed to four
for the equivalent AC solution), however for OWF U the cost of the additional AC cables particularly
onshore (with twelve AC cables required as opposed to two for the DC option) more than covers the
cost of the two converter stations (and their attendant platforms/compounds and switchgear).
It is the length of this onshore cable route for OWF U and Z1 from the landfall on the Norfolk coast to
the connection substation at Norwich that is addressed in option 5. This option looks at the impact on
the overall cost of these two wind farms were the onshore section to be constructed using a HVDC
double bipole overhead line rather than underground HVDC cable. The costs for HVDC overhead
line used in the cost estimates below have been derived from a manufacturer’s article in the IEEE
Power & Energy magazine [19]. Note that this option would not meet the current onshore GB SQSS
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criteria for the maximum power infeed loss (1320MW) for the loss of a double circuit overhead line,
or for the loss of two generator connection circuits, depending on how this line would be classified.
Option 6 considers the use of CSC HVDC technology to assess whether combining the Z1 and Z2
OWF, but reducing the combined installed capacity to 1680MW, and transmitting the power through
a single CSC converter pair/bipole may be an economic alternative for connection to Rayleigh than
using the two VSC converter pairs/bipoles in option 2.
Offshore Transmission
Option
OWF
3
OWF T connected to
Sizewell using HVDC VSC
T (DC)
Connection
Substation
Sizewell
Cost
£M
£356m
Cost
per MW
£k
£287k
Cost per MW
comparison
£
T(AC) to
Sizewell
£180k
4
OWF U connected to
Norwich using 245kV HVAC
U (AC)
Norwich
£590m
£477k
U(DC) to
Norwich
£331k
5
6
OWF U and Z1 jointly
connected onshore via
HVDC overhead line to
Norwich
OWF Z1 & Z2 combined
and reduced to 1680MW
installed and jointly
connected via HVDC CSC
to Rayleigh
U
Norwich
£811m
£328k
Z1
U & Z1 to
Norwich
£348k
Z1
Rayleigh
£1,057m
£629k
Z2
Z1 & Z2 to
Rayleigh
£457k
Table 15: Alternative connection costs for Norfolk Zone
6.4.3
Onshore reinforcement
Due to the proximity of parts of the offshore Norfolk zone to Sizewell (as little as 20km at points), a
portion of the Norfolk zone generation can be brought ashore via AC cables. The distance from the
offshore zone to Norwich and Rayleigh indicate that HVDC subsea cable could provide a more
economic solution for connection to these substations. The choice of technology impacts the local
substation works only in evaluating the onshore transmission reinforcements.
To enable the full export of the power generated by the OWF onto the onshore transmission system
plus the generation background assumed in the scenario, transmission reinforcement is required to
transfer power further south towards the Essex area.
Whether the Norfolk zone OWF are connected wholly into East Anglia or split between coonection
points in East Anglia and further south (such as Rayleigh), there is a common set of onshore
reinforcements arising out of the GB SQSS requirements. The additional incremental capacity
available due to the construction of a new section of OHL and substation reconfiguration at
Bramford, allows the full 4.4GW investigated to be connected within the East Anglia region thus
minimising offshore cable lengths. However, if the connection of new nuclear generation at Sizewell
is taken into account, further MITS reinforcement is required. The impact of this on the connection of
OWF is dependent on the relative timing of these developments.
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Extending the onshore transmission out to the coast to minimise the amount of onshore cabling from
the East Coast wind farms was not considered in detail. This solution would necessitate a new
400kV double circuit line from a new coastal substation to Norwich. As this option still injects the
output of the OWF into East Anglia it does not alleviate the congested Sizewell to Pelham circuit
corridor. In this way the onshore transmission reinforcements outlined above would still be required
and therefore this option was not considered further at this time. However option 5 in Section 6.4.2
does consider the use of HVDC overhead line from Norwich to the coast. As this route would
traverse the Norfolk Broads the use of either HVAC or HVDC overhead line would depend on
planning and project timescales.
6.4.3.1
Zonal Infrastructure Works (without Sizewell C)
The connection of HVDC converters at Norwich and Rayleigh substations would necessitate
additional switchgear and substation extensions. The remaining 1.1GW HVDC connection in this
zone cannot be accommodated in the existing Sizewell substation compound. As a result, the
connection proposal is for a new substation (constructed in or around the Sizewell area) and
connected to the existing Sizewell to Bramford overhead line route that would be a suitable collection
point for the OWF. The extent of these substation works would be driven by land availability and the
requirements of the GB SQSS.
With the levels of OWF assumed in this zone, the increased cable costs associated with extending
further inland to Bramford substation would outweigh the cost of establishing a new substation at
Sizewell, given the cost assumptions used.
The reinforcements required within the East Anglia geographical zone, have been identified at a total
cost of £171m and include a new substation at Bramford (to accommodate the increase in power
flows under system contingencies), a new circuit route from Bramford to Pelham and a new circuit
route from Bramford to Rayleigh via Braintree. The new circuit routes are created by the installation
of a new section of overhead line from Bramford substation to the circuit tee-point near Twinstead
The locations of these potential major reinforcements required against the input assumptions used
are illustrated in green on Figure 22, below.
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Figure 22: Norfolk Zone Local Onshore Transmission Network and Location of Potential Onshore
Transmission Reinforcement
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6.4.3.2
Zonal Infrastructure Works (with Sizewell C)
The connection of Sizewell C nuclear generation requires the construction of a new 400kV
substation and overhead line reinforcements out of the East Anglia area. This includes those
reinforcements highlighted in Section 6.4.3.1 plus the reconductoring of the existing RayleighCoryton-Tilbury overhead line route.
Similar to the scenario without the new Sizewell C nuclear plant, the connection of a HVDC converter
at Norwich (1.1GW) substation would necessitate additional switchgear and a substation extension.
The connection of the new Sizewell C plant initiates the construction of a new substation as well as
the substantial transmission system reinforcements highlighted above. Here it is assumed that this
new substation can be extended to enable connection of a single 1.1GW HVDC converter.
The approach towards establishing the overall onshore/offshore optimum network solution for this
generation background was initially to try and minimise onshore reinforcement as much as possible
by cabling offshore in order to reduce the timescales for connection of OWF (given the relative lead
times of onshore vs. offshore transmission build). In taking this approach, the connection of 2.2GW
into Rayleigh, along with the associated local substation work required, was introduced. This solution
is considered optimum for this generation background if it is assumed that the current, approach to
onshore transmission investment continues and that financial commitment is required from
generators in order to invest in the necessary transmission capacity. This solution provides a trade
off between cost and time to delivery if the aforementioned assumption is made.
However, if onshore reinforcement were to begin in advance of financial commitment from users, it
may be possible for a more economic solution to be delivered within the necessary timescales.
There is potential for the total capacity of OWF in the Norfolk zone to connect into the East Anglia
area in addition to Sizewell C nuclear generation, therefore reducing overall offshore cable lengths
and hence costs, if a new OHL route were to be established from Walpole to a new substation on the
Cottam – Eaton Socon line (highlighted in orange on Figure 22) as well as the reinforcements
highlighted above.
One final alternative option investigated, in order to further reduce onshore reinforcement
requirements, was the connection 2.2GW of Norfolk OWF further south into Barking via the river
Thames. The intention with this option was to bring the generation into the onshore transmission
system as close to the demand as possible. Due to the complexity of delivering such a scheme, the
lack of land availability at Barking for siting HVDC converter stations and a significant increase in the
overall cost of this option relative to those proposed, this option was discounted.
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6.5
Hastings
Option
1
0.5GW
AC at
Bolney
OWF
AA
Offshore
Transmission
£M
£182m
Onshore Transmission
Substation
Network
Extension
Reinforcement
£M
£M
1.4
0
Total
£M
Comments
£184m
This does not
include the cost
of reactive
compensation
equipment
required to meet
reactive
requirements set
out in the SO-TO
code.
Table 16: Connection cost for Hastings Zone
Figure 23: Hastings zone connection overview
6.5.1
Offshore connection
Due to the nominal capacity (500MW) of the offshore wind farm (OWF) located in the Hastings zone
and the distance to the potential connection point at Bolney a HVDC connection solution was
discounted for economic reasons. Instead an HVAC solution has been proposed consisting of two
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offshore 33/245kV substations interconnected with a single three core 245kV cable, and each with a
single three core 245kV shorelink cable to transmit the power accumulated from the wind farm to a
transition pit located at the landing point onshore. From this transition pit six single core 245kV
cables have been routed to the potential connection point at Bolney 400kV substation. The onshore
cable route follows the road network as much as possible however there are a number of obstacles
that would need to be crossed along the proposed route. The estimated cost for directional drilling
under these obstacles has been included as part of the overall offshore connection cost estimate.
Due to the total HVAC cable length of this connection, reactive compensation is required to maintain
adequate power transfer levels. This reactive compensation has been located both on the offshore
substations and in an onshore substation compound adjacent to Bolney substation along with the
associated switchgear and step up transformers which form part of the offshore transmission assets.
Both the offshore and onshore substations have been designed to comply with the offshore SQSS
proposals (see Section 3.4) and are represented in diagrammatic form in Senergy Econnect drawing
1845 009 (p34). It has been assumed that a two AIS switchbay extension to Bolney 400kV
substation would be required to connect the Hastings OWF.
6.5.2
Offshore connection alternatives
Alternative connection points were considered at the existing National Grid 400kV substation at
Ninfield, and at a new substation to be created between Shoreham on Sea and Bolney. The former
option was discounted due to the extended cable route length (and hence cost), while the latter was
discounted because of the cost of the onshore transmission network extension necessary to create
and then connect this new substation (see Section 6.5.3) compared to the cost of taking a cable all
the way to Bolney.
6.5.3
Onshore reinforcement
For connections of the Hastings polygon, extension of the existing onshore 400kV substation at
Bolney is recommended. No further infrastructure costs are incurred against the input assumptions of
the scenario.
Alternative options have considered similar connections to Ninfield, but these were dismissed due to
a significant increase to the offshore transmission costs and minimal change to onshore
requirements.
An alternative option of providing a 400kV OHL from Bolney towards the coast and establishing a
new 400/132kV substation close to the South Downs was considered to reduce the onshore section
of the offshore transmission system (due to the substantial cost of onshore AC cable). This solution
proposed the adoption of a section of existing 132kV OHL and reconstructing it as 400kV. The
increased cost of the new substation and upgrade work was greater than the savings in onshore
transmission cabling cost, and this option was not taken further.
This part of the onshore system is characterised by one 400kV double circuit from Kemsley
substation passing Canterbury North, Sellindge, Dungeness, Ninfield and Bolney before branching
out into further routes at Lovedean. The significance of this solitary double circuit, is that the amount
of generation connecting into this single route is limited by the need to cater for the loss of a double
circuit overhead line route in planning transmission capacity (outlined in the GB SQSS). For the fault
outage of a section of this double circuit route between Kemsley and the new Cleve Hill substation
west of Canterbury North, all the generation connected southwest on this route will accumulate until
it reaches Lovedean before it has further outlets onto the rest of the system. The scenario used for
this study assumes one new 1.6GW nuclear unit at Dungeness. This 1.6GW, coupled with 0.5GW
from the proposed Hasting OWF and a potential further 1.9GW import from the Anglo-French HVDC
link would mean that if a second nuclear unit were to connect at Dungeness, a new 400kV OHL
route would be required out of this region. This region of the system is illustrated in Figure 24, below.
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Figure 24: Hastings Zone Local Onshore Transmission Network
If all currently contracted generators connected to this area of the system were to be considered in
conjunction with the possibility of imports on the Anglo-French link, there would be no spare capacity
on this part of the onshore transmission system. The timescales for connecting a project in this
region would be impacted by those associated with any onshore transmission reinforcement
requirements.
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6.6
West Isle of Wight
Option
1
0.5GW AC
to
substation
at
Chickerell
OWF
DA
Offshore
Transmission
£M
Onshore Transmission
Substation
Network
Extension
Reinforcemen
£M
t £M
£160m
£15m
0
Total
£M
Comments
£175m
This does not
include the cost
of reactive
compensation
equipment
required to meet
reactive
requirements set
out in the SO-TO
code.
Table 17: Connection cost for West Isle of Wight Zone
Figure 25: West Isle of Wight zone connection overview
6.6.1
Offshore connection
Due to the nominal capacity (500MW) of the offshore wind farm (OWF) located in the West Isle of
Wight zone and the distance to the potential connection point at Chickerell a HVDC connection
solution was discounted for economic reasons. Instead an HVAC solution has been proposed
consisting of two offshore 33/245kV substations interconnected with a single three core 245kV cable,
and each with a single three core 245kV shorelink cable to transmit the power accumulated from the
wind farm to a transition pit located at the landing point onshore. From this transition pit six single
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core 245kV cables have been routed to the potential connection point at Chickerell 400kV
substation. The onshore cable route follows the road network as much as possible however there
are a number of obstacles that would need to be crossed along the proposed route. The estimated
cost for directional drilling under these obstacles has been included as part of the overall offshore
connection cost estimate. Due to the total HVAC cable length of this connection, reactive
compensation is required to maintain adequate power transfer levels. This reactive compensation
has been located both on the offshore substations and in an onshore substation compound adjacent
to Chickerell substation along with the associated switchgear and step up transformers which form
part of the offshore transmission assets. Both the offshore and onshore substations have been
designed to comply with the offshore SQSS proposals (see Section 3.4) and are represented in
diagrammatic form in Senergy Econnect drawing 1845 009 (p34). It has been assumed that a two
GIS switchbay extension to Chickerell 400kV substation would be required to connect the West Isle
of Wight OWF.
6.6.2
Offshore connection alternatives
Alternative connection points were considered at the existing National Grid 400kV substation at
Mannington, and at a new substation to be created between Chickerell and Mannington on the
existing 400kV overhead line route, however both these options were discounted due to the
extended cable route length (and hence cost), and the difficult terrain and environmental
designations along the coastline between Weymouth and Bournemouth.
6.6.3
Onshore reinforcement
For connections of the West Isle of Wight wind farm, extension of the existing onshore 400kV
substation at Chickerell is recommended. No further infrastructure costs are incurred against the
input assumptions of the scenario.
An alternative option considered connection to Mannington, but this was dismissed due to a
significant increase in the length of both onshore and offshore cabling required along with the
associated increase in costs and minimal change to onshore transmission network requirements.
The onshore transmission network in this area consists of a 400 kV double circuit transmission line
that runs west from Nursling substation near Southampton, via substations at Mannington (inland
from Bournemouth), Chickerell (Weymouth) and Axminster to Exeter. East of Nursling the line
connects with generation sites at Fawley and Marchwood before branching out into the wider system
at Lovedean substation near Portsmouth. The line route is closest to the coast between Chickerell
and Axminster but otherwise lies several kilometres inland. (Fig 26)
West of Exeter, the line continues to Indian Queens in Cornwall and then approximately follows the
North Cornwall and North Devon coast back to Taunton. There it connects with another overhead
line running directly from Exeter and a single double-circuit line then passes through Somerset to
Hinkley Point and onwards to connect to the wider system at Melksham. (Fig. 26 refers)
The transmission system must be designed and operated as required by the GB SQSS so that the
loss of a section of double circuit line causes no overloading or other unacceptable system
performance. Following such an outage on the line to the east of any wind farm connection, the
power from the wind farm would have to flow west to Exeter and then via Hinkley Point to Melksham.
It would therefore combine with the power from generators at Langage, from any wind farms in the
Bristol Channel and from nuclear generation at Hinkley Point. This combined power flow could be
sufficient to trigger a need for significant reinforcements in this area of the network. The extent and
timing of these reinforcements is subject to the number of nuclear units assumed to be connected at
Hinkley Point, the amount of offshore wind generation expected to be connected into the south west
peninsula and the extent to which wind generation is assumed to share capacity with conventional
generation in this area.
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At the time of writing, 3.3GW of nuclear generation (i.e. 2 x1.65GW units) is contracted to connect at
Hinkley Point in 2016. However 1.512GW of offshore wind generation, not involved in either the
Round 1 or Round 2 leasing process, is also already contracted to connect at Alverdiscott in 2014. In
combination, this level of generation in this area of the South West would trigger the need for a new
40km overhead line route as well as significant uprating of existing routes
This region of the system is illustrated in Figure 26, below.
Figure 26: West Isle of Wight Zone Local Onshore Transmission Network
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6.7
Bristol Channel
Figure 27: Bristol Channel zone AC connection overview (options 1&2)
Option
OWF
Offshore
Transmission
£M
Onshore Transmission
Substation
Network
Extension
Reinforcemen
£M
t £M
Total
£M
1
1.5GW AC
to new
substation
on Torridge
estuary
EA
£345m
£37m
£48m
£430
2
1.5GW AC
to existing
Alverdiscott
substation
EA
£404m
£34m
0
£438
3
1.1 GW DC
to existing
Alverdiscott
substation
EA
£413m
33
0
£446
Comments
- new substation
- new DNO
supply
- Alverdiscott
double busbar
- Alverdiscott
double busbar
- no MITS
without new
nuclear at Hinkley
- Alverdiscott
double busbar
- no MITS
without new
nuclear at Hinkley
Table 18: Connection cost for Bristol Channel Zone
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Figure 28: Bristol Channel zone DC connection overview (option 3)
6.7.1
Offshore connection
The connection of the Bristol Channel zone OWF presents a number of options. The nominal
capacity of this zone (1.5GW) exceeds the nominal capacity of a single HVDC VSC converter
pair/bipole (1100MVA) while for an HVAC connection five 245kV three core subsea cables are
required to transmit this power output ashore. The accumulation of 1.5GW from the wind farm array
itself also requires an additional 33/245kV offshore substation to be installed with the wind farm
effectively split into three sections. In addition there are two possible connection points onshore, the
existing National Grid 400kV substation at Alverdiscott, and a potential new 400kV substation to be
established on the bank of the Torridge estuary.
Option 1 in Table18 considers an HVAC connection for the full 1.5GW to this new substation.
Offshore the OWF connection designs are based on three 33/245kV offshore substations each
consisting of three 160MVA 33/245kV transformers with associated GIS switchgear. From the
Northern offshore substation, one 245kV three core cable is routed directly to the landing point on
the Torridge estuary, while the other 245kV three core cable is connected to the 245kV busbar at the
Western offshore substation. The Western and Eastern offshore substations both have a further two
245kV three core cables connecting them directly to the landing point on the Torridge estuary,
providing a total of five shorelink HVAC cables and one platform HVAC interconnection cable
(between the Northern and Western substations). These cables are then routed to a 245kV busbar in
a compound adjacent to the new National Grid substation, the voltage is then stepped up to 400kV
via two 750MVA transformers for input into the National Grid via two GIS 400kV double busbar
switchbays. As this new substation could potentially be on or very close to the bank of the estuary no
transition to single core underground cables has been deemed necessary.
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Option 2 considers the same HVAC design offshore but this time with the existing substation at
Alverdiscott as the connection point, which extends the offshore cable route length and also requires
transition to fifteen separate 245kV single core underground cables for the 5km of onshore route
between the landfall point and Alverdiscott substation.
Option 3 considers the HVDC VSC option and follows the same design as used for the Dogger Bank,
Hornsea, and Norfolk zones. As a result the installed capacity of the wind farm has been dropped
from 1.5GW to just over 1.2GW (which also means only two 33/245kV offshore substations are
required) to allow one 1110MVA HVDC VSC converter pair/bipole to be utilised.
6.7.2
Offshore connection alternatives
Option 4 shown in table 19 provides the alternative HVDC solution which utilises the extra power
transfer capacity of a CSC converter pair/bipole link to transmit the full 1.5GW from the Bristol
Channel zone. Offshore this solution required the three 33/245kV offshore substations of option 1 but
here the exporting 245kV cables are connected to a 245kV busbar on the offshore CSC HVDC
converter platform with the power being transmitted through a pair of HVDC Mass Impregnated
cables with integrated return conductor (which has the advantage of allowing for 50% operation for
the loss of one cable) to an identical CSC converter onshore in a compound adjacent to Alverdiscott
substation where the power is converted back into AC for input into the National Grid through two
400kV AIS double busbar switchbays. The onshore impact of this alternative solution has not been
investigated in detail.
Offshore Transmission
Option
OWF
4
1.5 GW to existing
Alverdiscott substation
utilising CSC HVDC
EA
Connection
Substation
Alverdiscott
Cost
£M
£590m
Cost
per MW
£k
£393k
Cost per MW
comparison
£
1.5GW (AC) to
Alverdiscott
£292k
Table 19: Alternative connection costs for Bristol Channel Zone
6.7.3
Onshore reinforcement
For either of the AC or DC offshore connection options a new 400kV substation is to be added at the
existing Alverdiscott 400/132kV substation site. Currently the 400kV equipment is simply Teeconnected to the overhead line route, but a full double busbar 400kV substation will be required for
the connection of 1.5GW.
With the AC connection, an option is to seek to construct a new 400kV overhead line from
Alverdiscott towards the coast. This would effectively replace an existing 132kV line over this portion
of the route and create a new connection point for the wind farm with a new 400/132kV substation.
This additional network extension is estimated at £48m.
The generation scenario described in Section 5.2 assumes the closure of Hinkley Point B (1.26 GW)
and the commissioning of one 1.6 GW European Pressurised Water Reactor (EPR) at Hinkley Point
in the timescales considered. As explained in Section 6.6.3, all generation developments in the
South West interact and, in combination, may drive a need for reinforcement. If a further 1.6 GW unit
were to materialise at Hinkley Point, major reinforcement would be required. This could potentially
include the need for a 40 km overhead line route as well as significant uprating of existing routes.
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At the time of writing, 3.3GW of nuclear generation (i.e. 2 x1.65GW units) is contracted to connect at
Hinkley Point in 2016. However 1.512GW of offshore wind generation, not involved in either the
Round 1 or Round 2 leasing process, is also already contracted to connect at Alverdiscott in 2014
This region of the system is illustrated in Figure 29, below.
Figure 29: Bristol Channel Zone DC Local Onshore Transmission Network
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6.8
Irish Sea
Onshore Transmission
Offshore Transmission £M
Option
Substation Extension £M
Network Reinforcement £M
OWF
Connection
Substation
Cost
£M
IA
Deeside
£416m
(DC)
Total
£M
Comments
£86m
1
1.1GW
at Wylfa
2.2GW
at
Deeside
1.1GW
at
Stanah
1.1GW
at Wylfa
2
2.2GW
at Pentir
1.1GW
at
Stanah
LA
Deeside
£420m
£0m
JA
Wylfa
£266m (AC)
£7m
NA
Stanah
£407m
£30m
IA
Pentir
£379m (AC)
Pentir
£401m
(DC)
JA
Wylfa
£266m
(AC)
£7m
NA
Stanah
£407m
£30m
£1,632
£6m
LA
£186m
£1,682
Possible land
restrictions at
Deeside if CSCHVDC link is
used for
Hunterston to
Deeside Link.
The
establishment of
a second circuit
on the existing
route from Pentir
to Trawsfynydd
would be
required to
deliver this
option.
Table 20: Connection cost for Irish Sea Zone
6.8.1
Offshore connection
Again due to the proximity of the OWF IA and JA in the Irish Sea zone to their potential respective
connection points at Pentir and Wylfa, cost estimates for both an HVAC and HVDC solution were
derived. However due to their distance offshore, AC solutions for OWF LA and NA were not deemed
pragmatic and hence only HVDC connection solutions have been assessed for these two wind
farms.
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Figure 30: Irish Sea zone connection overview
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The HVDC and HVAC connection designs for these wind farms are the same as those discussed in
the previous sections (and shown diagrammatically in Senergy Econnect drawings 1845-010 (p35)
and 1845-011 (p36)) and hence are not re-iterated here. The options for connecting wind farm IA to
either the existing National Grid 400kV substation at Pentir or via a longer route to the existing
National Grid 400kV substation at Deeside has been shown due to the impact of each connection on
the wider onshore transmission reinforcements required. The respective reinforcements are
discussed in more detail in Section 6.8.3.
6.8.2
Offshore connection alternatives
With the relatively short cable distances between OWF IA and the substation at Pentir, and OWF JA
and the substation at Wylfa, it is the HVDC solutions for these wind farms that are more expensive
than the HVAC alternatives, again due to the cost of providing the HVDC converters, and associated
extra platform and switchgear. However for the connection of OWF LA (option 5) the longer cable
route length makes the HVDC solution more cost effective.
Option 6 looks at the use of HVDC CSC technology to transmit the power generated in polygon IA,
expanded to an installed capacity of 1680MW to the connection substation at Deeside. The design
would follow the same principles as that discussed for the Bristol Channel zone option 4 in Section
6.7.2.
Offshore Transmission
Option
OWF
3
OWF IA connected to Pentir
using HVDC VSC
IA (DC)
Connection
Substation
Pentir
Cost
£M
£395m
Cost
per MW
£k
£319k
Cost per MW
comparison
£
IA (AC) to
Pentir
£306k
4
5
6
JA (AC) Wylfa
OWF JA connected to
Wylfa using HVDC VSC
JA (DC)
OWF LA connected to
Pentir using HVAC
LA (AC)
OWF IA enlarged to
1680MW installed and
connected via HVDC CSC
to Deeside
Wylfa
£354m
£286k
£215k
LA (DC) Pentir
Pentir
£454m
£366k
£323k
IA
Deeside
£723m
£430k
IA (DC)
Deeside
£336k
Table 21: Alternative connection costs for Irish Sea Zone
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6.8.3
Onshore reinforcement
For the Irish Sea zone, connections to the onshore transmission system were considered in the
North Mersey area to the existing substations of Heysham and Stanah for a total of 1.1GW. Due to
severe land restrictions at Heysham and similar offshore cable lengths for both, Stanah was
considered to be the best interface point with the onshore transmission system. The standard
substation extensions associated switchgear will be required at Stanah in order to provide the
interface with the offshore network.
Due to the location of the wind farms and zone polygons, it was most economic to connect the
remaining 3.3GW into the North Wales area. Connection into the existing substations at Wylfa, Pentir
and Deeside were considered.
The optimum solution for the Irish Sea OWF connecting into North Wales is also influenced by the
possibility of undertaking onshore transmission reinforcement in advance of financial commitment
from users being in place to do so.
The limiting section of the network in this region is the single circuit between Pentir and Trawsfynydd
substations. The scenario analysed assumes that the existing nuclear generator at Wylfa is closed
and that no new nuclear is connected in the timescales considered. Should nuclear replanting occur
at Wylfa, there is a definite need to reinforce this section of the network with a second circuit along
the existing route.
From an offshore transmission system perspective, the most economic solution is the connection of
the entire 3.3GW of Irish Sea OWF into Wylfa and Pentir. An alternative solution, in order to avoid
significant onshore reinforcement is to still connect 1.1GW into Wylfa, but to take the remaining
2.2GW into Deeside. There is a risk with this solution that sufficient land may not be available at
Deeside, as these connections would interact with the potential development of an HVDC link from
Hunterston into Deeside, which could be either a CSC or VSC HVDC link depending on the
requirements identified.
Therefore, if onshore reinforcement of the Pentir – Trawsfynydd route (highlighted in green on Figure
26.1) was undertaken strategically, in advance of connections coming forward, this would help in
connecting both offshore wind and/or any nuclear generation in this region. This solution has the
potential to reduce the cost of the offshore network.
This region of the system is illustrated in Figure 31, below.
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Figure 31: Irish Sea Zone Local Onshore Transmission Network and Location of Potential Onshore
Transmission Reinforcement
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7
Delivery Issues
7.1
Offshore Installation & Manufacturing resource
From the connection designs presented in the earlier sections of this report it is apparent that
significant quantities of HVAC and HVDC equipment will be required to complete the connection of
the Round 3 offshore wind farms. Senergy Econnect is aware of anecdotal evidence of problems
being faced by developers currently in sourcing major items of plant including wind turbines,
transformers, switchgear and cables, and hence development of the Round 3 projects may well be
constrained by the ability of developers to procure (and manufacturers to provide) the physical
assets required to create their wind farms. The installed capacity and timetable proposed for Round
3 may also make the availability of offshore installation vessels a potential bottleneck in the
construction phase.
This section of the report investigates these issues in more detail. Specifically, it reviews the latest
industry major publication assessing supply chain issues and documents the outcomes of
communications with major suppliers in order to arrive at a more thorough assessment of supply
chain issues facing the development of offshore wind projects.
The suite of documentation supporting the Government UK Renewable Energy Strategy
Consultation document [20], and the BERR Publication, “Quantification of Constraints on the Growth
of UK Renewable Generating Capacity”, Sinclair Knight Merz, June 2008 (The BERR Report) [18]
has been used in this assessment.
7.1.1
HVAC and HVDC subsea cables
The supply chain associated with high voltage alternating current (HVAC) and high voltage direct
current (HVDC) subsea cables is a significant constraint to growth. HVAC and HVDC cables are
required to connect offshore wind farms to the onshore electricity infrastructure.
From the analysis undertaken in this report, Senergy Econnect estimate that about 1200km of HVAC
three core and single core cable and 5,200km of HVDC underground / subsea cable will be required
for Round 3 projects. The UK does not have a high voltage subsea cable manufacturing capability
and there are only three suppliers of HVAC and HVDC subsea cables in Europe (i.e. ABB, Nexans
and Prysmian) with lead times of between two and three years depending on the type of cable
required.
The technology associated with the manufacture of high voltage cable is vested with the existing
cable suppliers and it is unlikely that a new entrant could get the product to market within several
years, if at all, because of the research needed to overcome the technological barriers. Accordingly if
high voltage subsea cables are to be manufactured in the UK it will be necessary to encourage one
or more of the existing European suppliers to set up a manufacturing facility in the UK at a suitable
port location to facilitate loading onto specialist cable laying vessels. Setting up such a facility is
estimated to cost about £35 million and would take about three years [18] to reach production.
Senergy Econnect are aware that the lead times in HV cables has increased to 18 -24 months over
the past year due to the large demand from other sectors such as utility infrastructure, and oil and
gas.
However a number of existing suppliers do see the future potential capacity requirements of the
offshore wind as well as other sectors and have firm plans to increase their capacity through
investment in facilities, although the delay from investment to first supply from new production lines is
of the order of two years.
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7.1.2
HVDC converter equipment
Although not presently a supply chain constraint, the demand for HVDC converter equipment that will
be needed to connect offshore wind farms located more than 60km from the onshore connection
point is likely to increase significantly as the more distant offshore wind farm sites are developed in
the North Sea. It will be at least five years before these distant sites are constructed, therefore as
these projects become committed the HVDC converter suppliers are confident that there is sufficient
time to increase manufacturing capacity to meet demand if they have sufficient assurance that these
projects will go ahead. However Senergy Econnect have anecdotal evidence that one manufacturer
is revising downwards their short to medium term forecasts for supplying the offshore market in the
UK because of the delays in progressing offshore projects through the GB planning, consenting, and
regulatory process .
With each HVDC VSC converter taking approximately nine months to manufacture, a number of
converters would have to be manufactured concurrently in order to meet the timetable for Round 3
assuming all the zones are developed simultaneously. It should be noted that the offshore
programmes of other countries and an increase in HVDC projects around the world will coincide with
the Round 3 build programme, and hence Round 3 developers or their Offshore Transmission
Owners may potentially need to commit to production slots up to three or more years in advance to
avoid the converters becoming a constraint. In order for the HVDC suppliers to have the confidence
to increase their manufacturing capability, they will require an order book to be in place, which in turn
means that the Offshore Transmission Owner regime needs to ensure that procurement of
equipment is triggered as early as possible in the process so that these lead times can be managed
and reduced.
7.1.3
Balance of plant equipment (e.g. transformers, switchgear, etc)
Although there are significantly more suppliers of balance of plant equipment than HV cable
suppliers, the worldwide demand for this type of equipment is forcing up prices and prolonging
delivery times. The lead time for transformers, a key long-lead element of the offshore substations,
has increased to around 36 months over the past year. Currently the lead time for switchgear can
take up to 12 months for switchgear rated at 132kV and above and up to six months for switchgear
rated at 33kV and below.
In reality the lead time from placement of order on an offshore project to energisation of the on and
offshore substations is in the order of three years, once the preparatory design work, installation and
commissioning is taken into account.
7.1.4
Assessment of the availability and cost of cable installation vessels
The view from suppliers is that they can meet the near-term capacity requirements and although it
will take significant investment, they can increase capacity fairly quickly to meet future requirements,
and there is a willingness to do so within the right frameworks. With a global pool of more than
twenty suitable vessels, cable installation is not expected by those involved to present a bottleneck.
Installation vessel availability is a significant issue but generally higher cost solutions are likely to
remain available, though this may price some projects out of the market. The following Table
illustrates the cost, capability and availability of the vessels owned and operated by one cable laying
company: -
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Item
Capability
Number of Vessels
Seven under ownership at various locations
worldwide
Number of vessels allocated specifically for offshore
wind industry
Three to Four vessels
Typical lead time
Two to three months
Cost
132kV cable laying
@£80k /day
5km per day ploughing typical
33kV cable laying
@£60k per day
Vessel Operating limits
1.25 – 1.5m height of swell
12m/s wind speed
7+sec swell period
Table 22: Cable Installation Vessel parameters
(Courtesy of Global Marine Systems)
7.2
Onshore transmission network delivery programme
To construct the onshore transmission system proposed in this study under the present regulatory
regime National Grid would require to receive applications for connections for each of the zones that
sought connection capacity for the total capacity of that zone.
It has been assumed that the new Planning Act would apply to the overhead line works required.
Under this regime, for moderate overhead line works the minimum timescale that is envisaged to
undertake the required studies, environmental impact assessments and obtain consent is
approximately four years from approval to commence work. Following this period it is necessary to
add the time required to enter into commitment to obtain the required materials, undertake the
installation activities then obtain system access to commence the connection process. This leads to
an overall time period from approval to connection of around seven years. Where new transmission
transformers are required, allowance has to be made for delivery periods for these, which are
presently around 36 months.
Where new 400kV overhead lines are required, particularly reasonably long routes, then the time
periods to undertake the required assessments, consultation and consenting process may take
considerably longer
Obtaining access to the system to undertake the required connections (i.e. taking outages of
equipment) will have to compete with other demands such as maintenance and outages to
undertake works for other users, and commitments. With the level of uncertainty around which year
connections will be undertaken arising from the issues above, it is not possible to accurately identify
if system access constraints would seriously impact on the delivery programme. As National Grid
presently has commitments to provide connections for users that are not present in the study
background the existing system access plans do not provide a reliable basis to work against. It is
however, reasonable to assume for the east coast connections particularly, that available system
access will be a major constraint on the ability to deliver the required work. Any location that has
programmes of delivery that approach those for new Nuclear or other generation connections will
also face system access competition. If reinforcement was able to take place before financial
commitment from users is in place, it may be possible to optimise the system outages required and
spread these out over a longer time period.
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8
Conclusions
8.1
Methodology and Assumptions
The aim of this study was to identify the extent and costs of the works necessary to provide
optimised transmission connections for all of the Round 3 offshore polygons. The methodology and
assumptions used to assess the required works are set out in Sections 2 and 3.
Key among these assumptions is the view that the offshore transmission assets should be designed
to achieve a high utilisation, both to optimise the capital investment and also demonstrate an
economic and efficient solution to the regulator. Such a consideration will be likely to form part of
Ofgem’s decision making criteria in the granting of an offshore transmission licence.
Factors such as the variability of the wind resource and the operational availability of offshore wind
turbines dictate that the Round 3 wind farms will rarely be generating to the full extent of their
installed capacity, which would adversely impact the utilisation of a connection solution that was
rated to transmit total installed capacity. In light of these considerations a high level analysis was
therefore undertaken to ascertain the optimal ratio between the installed generating capacity offshore
and the transmission capacity of the offshore transmission assets. This optimal utilisation ratio (given
by the formula below) was determined to be 112% (see Appendix 1): Utilisation ratio =
Offshore transmission asset capacity
Installed generating capacity
In practice the offshore transmission asset designs provided in this report have a range of utilisation
ratios from 81% to 112% because of the zonal capacities identified by The Crown Estate and the
modular nature of the transmission assets themselves (with each additional cable providing a fixed
increase in transmission capacity). National Grid are in the process of leading a review of the
security standards for offshore generation connections to include projects of the size and distance
form shore associated with Round 3, at the request of Ofgem. This review will culminate in a set of
security recommendations including offshore transmission circuit capacity, which will be consulted
upon and incorporated as revised text in the GB SQSS.
8.2
Cost of Connecting Round 3 Offshore Wind Farms
A summary of the optimal connection costs broken down by zone is set out in Table22 below.
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ZONE
OWF
Total
Installed
Capacity
(MW)
Connection
technologies
Connection
Point (s)
TOTAL
COST (£m)
TOTAL
COST
Per MW
(£k)
Moray Firth
C
500MW
AC
New substation
on coast
£193m*
£386k
Firth of Forth
G
500MW
AC
Torness
£150m*
£300k
H1
1237.5MW
DC
Creyke Beck
£5,910m
£477k
H3
1237.5MW
DC
Creyke Beck
J
1240MW
DC
Creyke Beck
H2
1237.5MW
DC
Keadby
H4
1237.5MW
DC
Keadby
H5
1237.5MW
DC
Killingholme
I1
1240MW
DC
Killingholme
I2
1240MW
DC
Killingholme
M
1237.5MW
DC
New substation
on Lincolnshire
coast
N
1240MW
DC
New substation
on Lincolnshire
coast
T
1240MW
AC
Sizewell
£1,728m
£349k
Z2
1240MW
DC
Sizewell
U
1237.5MW
DC
Norwich
Z1
1237.5MW
DC
Norwich
Hastings
AA
500MW
AC
Bolney
£184m
£368k
West Isle of
Wight
DA
500MW
AC
Chickerell
£175m
£350k
EA
1500MW
AC
New substation
on Torridge
Estuary
£430m
£287k
IA
1237.5MW
DC
Deeside
£1,632m
£329k
LA
1240MW
DC
Deeside
JA
1237.5MW
AC
Wylfa
NA
1240MW
DC
Stanah
£10,402m
£403k
Dogger Bank
Hornsea
Norfolk
(without
Sizewell C)
Bristol
Channel
Irish Sea
TOTALS
25,795MW
Table 23: Optimal Connection Costs broken down by Zone
*Total reinforcement costs dependent on GB transmission owner study currently in progress
The total cost for connecting the Round 3 wind farm projects, assuming no inclusion of Sizewell C,
and the optimal design solutions identified in this report is £10,402 million. Note that this Figure is
based on 2008 price levels for the equipment required and does not allow for the additional
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equipment such as Static Var Compensation that may need to be installed at the onshore connection
point of the HVAC connection solutions in order for the Offshore Transmission Owners to meet the
reactive capability requirement of the System Operator/Transmission Owner code (e.g. an SVC
sufficient to provide dynamic reactive capability for a 300MW wind farm would cost in the order of
£12m) . Sensitivities were also investigated in some areas where new nuclear developments could
occur in the same region and within the same timescales as the Round 3 development. If
transmission reinforcement was not undertaken in an optimised manner on a strategic basis then
offshore transmission asset costs could increase as a result of having to find alternative more distant
connection points. An example of this is the Norfolk zone where the inclusion of Sizewell C increases
the offshore transmission asset cost by £245m. As a function of these designs, the total installed
generating capacity connected for Round 3 is 25,295MW (with a connection capacity of 22,980MW)
with a £/MW cost ranging from £287k to £477k.
8.3
Individual Versus Aggregated Connections
The power transfer capabilities of the HVAC and HVDC technologies available coupled with the
potential installed capacity of the Round 3 OWF have to a large part dictated the offshore
transmission designs presented in this report and have determined that in the primary solution each
OWF is connected directly to an onshore connection point, with no interconnection between the
OWF in a particular zone.
The economies of using either HVAC or HVDC for these offshore transmission solutions have been
further explored within the report. Applying an HVAC and HVDC solution to the same OWF has
indicated that the choice of technologies used for the offshore transmission designs will be dictated
by the transmission distance and that the cable route length at which HVDC Voltage Source
Converter solutions become economic relative to an equivalent HVAC solution is between 60km and
80km.
Aggregated solutions, where multiple OWF are connected using ‘power corridor’ technologies such
as Gas Insulated Lines and HVDC Current Source Converters have been considered and costed,
although these solutions do not compare favourably with the individual offshore transmission designs
for the same OWFs in terms of cost per MW installed, except where solutions have been considered
that utilise dual bipole HVDC overhead lines as opposed to underground cable to traverse the long
distance overland routes from the coast to Norwich and Drax substations. Such designs also do not
necessarily permit the connection of higher levels of generating capacity relative to the approach of
allocating a dedicated connection per wind farm.
This is not to say that consideration of aggregated connections should not pursued further as there
are likely to be benefits associated with this approach that are not considered in this report, for
example there will be environmental and planning benefits of consenting a single connection cable
route compared to multiple cable routes. However, it would indicate that, in terms of the physical
plant required to connect the Round 3 wind farms alone, there would appear to be little to be gained
by aggregating these OWFs through single connections. The option of connecting the Round 3 wind
farms to continental Europe has not been considered within this report, however such connections
would face the same power transfer capacity constraints highlighted in Section 6.2.2.
8.4
Deliverability of Round 3 Connections
Offshore infrastructure projects on the scale considered within this report would set a global
precedent, with unparalleled volumes of offshore HVAC and HVDC plant required to facilitate the
connections. The challenges posed in delivering the Round 3 offshore connections, regardless of the
design pursued, will therefore be significant. Investment will be required by existing suppliers in
expanding manufacturing facilities for HV cables, and in particular subsea cables. The HVDC VSC
market is still at an embryonic stage, with the converter/bipole ratings used in this report yet to be
deployed in the field. Hence there will be a technology risk as well as cost premium to be borne by
the ‘first comer’ offshore transmission owner to specify this technology.
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Again it is likely that manufacturing facilities would need to be expanded to accommodate demand
for these technologies should Round 3 be developed in the timescales desired. Assuming the supply
chain can be sufficiently stimulated; prices should drop as competition increases and with economies
of scale. The HVDC converter manufacturers are confident that they can increase manufacturing
capability to meet demand should they have sufficient assurance that projects will place orders.
However Senergy Econnect have anecdotal evidence that one manufacturer is revising downwards
their short to medium term forecasts for supplying the offshore market in the UK because of the
delays in progressing offshore projects through the GB planning, consenting, and regulatory process,
and the ability of the process to deliver the offshore wind farm capacity in the timescales desired.
It should be noted that the offshore programmes of other countries and an increase in HVDC
projects around the world will coincide with the Round 3 build programme, and hence Round 3
developers or their Offshore Transmission Owners may potentially need to commit to production
slots up to three or more years in advance to avoid the HVDC converters becoming a constraint.
In order for the HVDC suppliers to have the confidence to increase their manufacturing capability,
they will require an order book to be in place, which in turn means that the Offshore Transmission
Owner regime needs to ensure that the procurement of equipment is triggered as early as possible in
the process so that these lead times can be managed and reduced.
Suppliers of the installation vessels necessary to install the cables and offshore platforms are
currently confident in their ability to quickly ramp up capacity to meet the demands of Round 3,
although they acknowledge that to make the investment required in the timescales necessary they
will need the security of retainer agreements or firm orders in place.
An offshore infrastructure program on this scale may present significant commercial opportunity for
UK plc in the medium to long term, however it would also present significant development cost in the
short term. Such development costs are likely to be exacerbated by the shortage of engineering skills
within the UK as identified in the BERR report [18].
Establishing the large new compounds onshore to accommodate assets such as the multiple HVDC
converter stations, extending National Grid’s existing substations and creating the new substations
and overhead line routes necessary to integrate Round 3 into the existing onshore transmission
network will all require an efficient transition through the planning process if the desired timescales
are to be achieved. The passing into law of the recent planning bill which is the first step in the
creation of an Infrastructure Planning Commission to determine nationally significant projects should
therefore be welcomed.
8.5
Benefits of a co-ordinated approach
The design and costing process has considered a “total solution” capable of handling the entire 25
GW of Round 3 offshore wind. This assumes that the collective requirements for all the wind farms in
a zone are required and that the overall onshore transmission system changes will all occur in a
coordinated manner at any one location. Should piecemeal developments be undertaken, wind farmby-wind farm, and/or wind generation capacity change incrementally over a period of years, the
staggered timing of the works would result in multiple site/circuit extensions and this will increase the
overall onshore costs and environmental impact. In order to avoid this extensive stakeholder
engagement, coordination and collaboration is required.
By considering the connection requirements of zones as a whole, and by balancing the requirements
and crucially the costs of the offshore and onshore transmission assets, this report has sought to
indicate the optimal solutions for the connection of the Round 3 OWF projects, from an impartial
perspective. While individual OWF or even individual zones may be able to achieve a more
economically favourable connection in isolation, such an approach may lead to additional cost and/or
additional delays in the connection of Round 3 as a whole.
To mitigate this, the ongoing development of the offshore transmission regulatory regime should
carefully consider how the connection application process will work in practice to provide the co-
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ordination necessary to deliver the optimum solution. Detailed investigations should also be
undertaken into ‘no-regret’ onshore transmission reinforcements that can be taken forward
immediately to deliver the network capacity required.
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9
Recommendations
This report has identified the optimum outline connection designs in light of target generating
capacities and high level environmental constraints. This report has also identified some of the likely
challenges to be overcome in delivering the Round 3 connection designs. In order to further explore
the feasibility, costs and environmental issues surrounding Round 3 it is recommended that further
more detailed investigations be carried out into;
•
The environmental and planning constraints that may affect connection solutions for each
zone
•
The extent of constraints on supply chain that may impact delivery of the Round 3
connections
•
Raising the power transfer capacity of the HVAC and HVDC technologies to improve
economies of scale
•
Putting in place a process to effectively manage the Round 3 grid connection applications
and coordinate the on and offshore transmission works
•
‘No regret’ onshore reinforcement options that can be progressed immediately to provide the
necessary transmission capacity in a timely manner
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10
References
1.
East Coast Transmission Network, Technical Feasibility Study, Project 1845 v1.0 dated
March 2007.
2.
www.windpower.org Danish Wind Industry Association 2003
3.
"Rating cables in J-Tubes" by M. Coates of Engineering Materials Division, Era
Technology Ltd
4.
Table 41 Attachment to XLPE Cable systems – User’s Guide ABB
5.
Gas Insulated Lines –reliable power transmission towards new worldwide challenges in
hydro and wind power generation H.Koch, D.Kunze, S.Pohler, L.Hofmann, C.Rathke,
A.Mueller, CIGRE study committee B3, 2008 session
6.
GIL – Gas Insulated Transmission Line reference list - Siemens Power Transmission &
Distribution (28/05/08).
7.
Superconductor Power Cables – American Superconductor 2008
8.
Cost benefit methodology for optimal design of offshore transmission systems, P. Djapic,
G Strabac, SEDG July 2008
9.
Report on the recommendations arising from additional cost benefit analysis
10. http://eosweb.larc.nasa.gov NASA atmospheric science and data center, surface
meteorology and solar energy tables for Latitude 550 Longitude 20
11.
North Hoyle Offshore Wind farm annual report, URN no. 08/P47 BERR
12.
GB Security and Quality of Supply Standard
13.
Terms of Reference for GB Security and Quality of Supply Standard Review Group: via
National Grid Electricity website: http://www.nationalgrid.com/NR/rdonlyres/67B20E95-61EF4532-8557-659F7CD6D12A/15792/120207GBSQSSReviewGroupToR_FINAL_.pdf
14.
GB Seven Year Statement 2008, Chapter 7: GB Transmission System Performance –
Modelling of the Planned Transfer Condition
15.
http://www.nationalgrid.com/uk/Electricity/Codes/gbsqsscode/reviews/
Review GSR001
16.
http://www.ofgem.gov.uk/Networks/Trans/Offshore/ConsultationDecisionsResponses/Pag
es/ConsultationDecisionsResponses.aspx
Offshore Electricity Transmission – A
Joint Ofgem/BERR Regulatory Policy Update
17.
Djapic, P & Strbac, G (2008) Cost Benefit Methodology for Optimal Design of Offshore
Transmission Systems, BERR Centre for Sustainable Electricity & Distributed Generation,
July 2008.
18.
http://renewableconsultation.berr.gov.uk/related_documents, “Quantification of
Constraints on the Growth of UK Renewable Generating Capacity”, Sinclair Knight Merz.,
June 2008.
19.
The ABC’s of HVDC Transmission Technology IEEE Power & Energy magazine March
/April 2007 Vol 5 No2
20.
UK Renewable Energy Strategy Consultation document BERR June 2008
(http://renewableconsultation.berr.gov.uk/consultation/consultation_summary)
1845 Crown Estate Round 3 OWF connection study v1.0 (FINAL).doc
GB SQSS
Page 91 of 94
11
List of Appendices
Appendix 1
Offshore wind farm installed capacity / connection capacity study
Appendix 2
HVAC cable reactive compensation methodology
Appendix 3
Moray Firth C KEITH detailed costing
Appendix 4
Moray Firth C NEW SUBSTATION detailed costing
Appendix 5
Firth of Forth G TORNESS detailed costing
Appendix 6
Firth of Forth G EAST COAST IC detailed costing
Appendix 7
Dogger Bank H1 THORNTON detailed costing
Appendix 8
Dogger Bank H1 CREYKE BECK detailed costing
Appendix 9
Dogger Bank H2 DRAX detailed costing
Appendix 10
Dogger Bank H2 KEADBY detailed costing
Appendix 11
Dogger Bank H3 DRAX detailed costing
Appendix 12
Dogger Bank H3 KEADBY detailed costing
Appendix 13
Dogger Bank H3 CREYKE BECK detailed costing
Appendix 14
Dogger Bank H4 CREYKE BECK detailed costing
Appendix 15
Dogger Bank H4 KILLINGHOLME detailed costing
Appendix 16
Dogger Bank H4 KEADBY detailed costing
Appendix 17
Dogger Bank H5 CREYKE BECK detailed costing
Appendix 18
Dogger Bank H5 KILLINGHOLME detailed costing
Appendix 19
Dogger Bank I1 KEADBY detailed costing
Appendix 20
Dogger Bank I1 KILLINGHOLME detailed costing
Appendix 21
Dogger Bank I2 KEADBY detailed costing
Appendix 22
Dogger Bank I2 KILLINGHOLME detailed costing
Appendix 23
Dogger Bank J THORNTON detailed costing
Appendix 24
Dogger Bank J CREYKE BECK detailed costing
Appendix 25
Dogger Bank I+ CSC KILLINGHOLME detailed costing
Appendix 26
Dogger Bank I+ GIL KILLINGHOLME detailed costing
Appendix 27
Dogger Bank H2 & H3 DC OHL DRAX detailed costing
Appendix 28
Hornsea M SOUTH HUMBER BANK detailed costing
Appendix 29
Hornsea M GRIMSBY detailed costing
Appendix 30
Hornsea M LINCOLNSHIRE COASTAL SUBSTATION detailed costing
Appendix 31
Hornsea N SOUTH HUMBER BANK detailed costing
Appendix 32
Hornsea N GRIMSBY detailed costing
Appendix 33
Hornsea N LINCOLNSHIRE COASTAL SUBSTATION detailed costing
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Appendix 34
Norfolk T AC SIZEWELL detailed costing
Appendix 35
Norfolk T DC SIZEWELL detailed costing
Appendix 36
Norfolk U AC NORWICH detailed costing
Appendix 37
Norfolk U DC NORWICH detailed costing
Appendix 38
Norfolk Z1 NORWICH detailed costing
Appendix 39
Norfolk Z1 RAYLEIGH detailed costing
Appendix 40
Norfolk Z2 SIZEWELL detailed costing
Appendix 41
Norfolk Z2 RAYLEIGH detailed costing
Appendix 42
Norfolk U & Z1 DC OHL NORWICH detailed costing
Appendix 43
Norfolk Z+ CSC RAYLEIGH detailed costing
Appendix 44
Hastings AA BOLNEY detailed costing
Appendix 45
West Isle of Wight DA CHICKERELL detailed costing
Appendix 46
Bristol Channel EA AC NEW ESTUARY SUBSTATION detailed costing
Appendix 47
Bristol Channel EA AC ALVERDISCOTT detailed costing
Appendix 48
Bristol Channel EA DC ALVERDISCOTT detailed costing
Appendix 49
Bristol Channel EA CSC DC ALVERDISCOTT detailed costing
Appendix 50
Irish Sea IA DC DEESIDE detailed costing
Appendix 51
Irish Sea IA DC PENTIR detailed costing
Appendix 52
Irish Sea IA AC PENTIR detailed costing
Appendix 53
Irish Sea JA DC WYLFA detailed costing
Appendix 54
Irish Sea JA AC WYLFA detailed costing
Appendix 55
Irish Sea LA DC DEESIDE detailed costing
Appendix 56
Irish Sea LA DC PENTIR detailed costing
Appendix 57
Irish Sea LA AC PENTIR detailed costing
Appendix 58
Irish Sea NA STANAH detailed costing
Appendix 59
Irish Sea IA+ CSC DC DEESIDE detailed costing
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Appendix 1: Offshore Wind Farm installed capacity/connection capacity
study
1
Introduction
To date the connection of both on and offshore wind farms is calculated on enabling export of full
capacity despite the fact that the majority of the time the wind farm is not generating at full power.
The development of wind farms with a maximum output that exceeds the available grid capacity is
not common practice as it requires the wind farm to be constrained, as such, revenue during
periods of peak generation, however brief, is lost.
As the cost of connection for offshore wind farms is significantly higher than those experienced
onshore, and the uncertainty surrounding weather and tidal conditions to perform maintenance
functions may result in lower availability for offshore turbines, it may make sense to install a higher
installed generating capability than the connection capacity will allow. Such an approach could
result in better overall economics for the development despite being constrained at generation
peaks.
While wind farm developments are often considered in terms of costs per MW installed this is a
view that takes no account of the capacity factor (ratio of energy generated to maximum possible
energy output). Therefore, it could be argued that, from a financial perspective, a more appropriate
measure of costs would be cost per MWh generated over the lifetime of the wind farm.
From the perspectives of grid connection and economics, the question is - for a given scenario
which size is optimum?
To answer this question the economic drivers and associated sensitivities for an Offshore Wind
Farm need to be understood. This report provides an overview of a model developed to address
this question and provides conclusions to this analysis which have been used to determine
installed capacities for the Round 3 offshore wind farms identified within the main report.
2
Objectives
The objective of the Wind Farm Sizing model is to ascertain, at a high level, the optimum size of an
Offshore Wind Farm for a given connection capacity to assess the lowest ratio of cost per MWh
generated over the lifetime of a wind farm project, as shown in Figure A1.1
1845 Appendix 01 OWF installed-connection capacity study v1-0.doc
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Figure A1.1. Trend of Capex/lifetime energy generation (£/MWh) as installed capacity increases as a
percentage of connection capacity
3
The Model and Method
3.1
Assumptions
For an offshore location, measured wind speeds throughout a year are characterised by moderate
to fresh winds (5-10m/s), while winds that are strong gale force and above (>20 m/s), where
energy levels are maximised, are relatively uncommon. The wind variation for a standard site is
typically described using the Weibull distribution, such as that shown in Figure A1.2.
Figure A1.2. Weibull distribution [1]
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The black line in figure A1.2 is the average wind speed and separates the curve into two equal
areas.
Based on this curve it can be assumed that every site can be defined by a shape factor (which, as
the name suggests, defines the shape of the curve) and an average speed (which defines the
curve’s axis) that can be applied to mathematically model the wind profile at a site.
A shape factor of 2 is known as a Rayleigh distribution. In this study a shape factor of 2, which is
the most common in Europe, is applied alongside the average wind speed from real or implied data
for the North Sea. [2]
3.2
Constraints
The amount by which the installed generation capacity may be greater than a specified grid
connection capacity will depend upon the availability of the wind turbine generator (WTG) and the
balance between the cost of installing a WTG relative to the cost of connection.
3.2.1
Availability of the WTG
A WTG is considered unavailable when it is not capable of operating in productive conditions. This
may be as a consequence of a number of different aspects, for example, maintenance, fault
conditions, etc.
It is well documented that the availability of onshore WTGs is in the order of 97 – 98% [1];
however, in the offshore environment, due to the challenges of vessel availability and weather and
tidal windows, in particular, it is realistic to expect availability to be lower, for example, the
availability of North Hoyle Round 1 offshore wind farm is reported at 84.7% [3].
Understanding the wind speed distribution is crucial in determining the energy utilisation of the
connection assets and the energy lost by constraint. For a low wind speed site, more WTGs can be
installed above a nominal connection capacity without an equivalent increase in constraint costs.
Such ‘over-development’ could represent an economic advantage for the wind farm.
3.2.2
Cost of installed WTG vs. cost of connection.
It is estimated that the typical cost per MW installed (including grid connection) for offshore wind
farms is presently in the range £1.8m - £2.3m [4]. As the grid connection increasingly represents a
significant proportion of these costs, especially as these offshore wind farms are located further
from their points of connection, then minimising these costs has more influence on the project
financial model.
Conversely, should the cost of the WTG increase relative to the connection costs then it may be
anticipated that there would be little or no advantage to increasing the installed capacity beyond
the available connection capacity.
3.3
3.3.1
Model Set-up and Analysis Methodology
WTG Technology
Different WTG technologies have different power curves. The turbines used in this analysis are as
follows; Siemens 3.6MW, Repower 5MW and Multibrid 5MW. The power curves for these WTG
have been used to calculate the number of turbines required for the best case scenario and hence
determine the ideal wind farm size.
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The engine of the model is based upon the power curve of the selected WTG. As the wind farm is
‘enlarged’ beyond the connection capacity the amount of constraint on the wind farm increases.
This is simulated in the model by reducing the maximum power that each WTG can generate. As
more WTGs are installed the level of constraint is increased and the subsequent total wind farm
power that can be generated is reduced due to the electrical constraint of the connection capacity.
This is shown in Figure A1.3.
Figure A1.3. Power curve constraint
3.3.2
Connection Costs
This input variable is at the discretion of the model user, typical costs of connection applied here
are approximated at £0.7m per MW [4] 1.
3.3.3
WTG Costs
This input variable is at the discretion of the model user and constitutes all costs other than
connection costs, the majority of which is the cost of the WTG. Typical costs applied are
approximated at £1.5m per MW [4]
3.3.4
Average Wind Speed
This input variable is at the discretion of the model user. For offshore wind farms in the UK this has
been approximated at 9m/s, as shown in Figure A1.4 [5].
1
The actual connection costs identified within the report range between £287k and £477k per MW based on
a 112% utilisation factor or £287k and £532k per MW based on a 100% utilisation factor which would
weaken the financial case for over installing capacity offshore, however it could also be surmised that for
Round 3 the WTG installed costs per MW may also reduce below £1.5m per MW which would in turn
strengthen the financial case for over-installing. Sensitivity to these variables has been assessed within this
analysis.
1845 Appendix 01 OWF installed-connection capacity study v1-0.doc
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Figure A1.4. Annual mean wind speed in UK [5]
3.3.5
WTG Availability
This input variable is at the discretion of the model user. Turbine availability is approximated at
90% based upon data from existing offshore wind farms [3].
3.4
Sensitivity Analysis
The aim of the sensitivity analysis is to gain an understanding of the limitations to the scale of
overdevelopment of the wind farms in relation to changes in the different constraint variables
identified in section 3.3.
The sensitivity analyses pertain to; ratio of connection costs to WTG costs, average wind speed,
and WTG availability.
3.4.1
Ratio of connection costs to installed WTG costs
This ratio is calculated on a per MW basis. The cost of installed MW includes costs associated with
the WTG machine, transportation and installation. The cost of connection includes the offshore
transmission assets and the substations both on and off shore. The ratio of installed WTG costs to
connection costs is stepped in the sensitivity analysis from 0.5 to 2.5.
3.4.2
Average Wind Speed
As the mean wind speed varies year on year, an analysis of the sensitivity to mean wind speed is
an important element. It should be noted that the energy production of the WTG is directly
1845 Appendix 01 OWF installed-connection capacity study v1-0.doc
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proportional to the average wind speed; as average wind speed increases the energy production of
an operational WTG increases; which will increase revenue and, therefore, reduce the cost per
MWh generated.
Typically, at an average wind speed of 6m/s, depending upon the WTG selected, the WTG is
generating at 10-25% of its maximum MWh output, while at wind speeds above16m/s the WTG is
generating at 100% of the maximum available MWh output. The energy produced by a wind farm
over the course of a year as a proportion of the total energy that the wind farm could possibly have
generated had the wind speed been constantly above 16m/s for example is given by the term
‘capacity factor’ (CF). Capacity factors tend to be higher for offshore wind farms than those
onshore due to higher average wind speeds and less turbulence in the air flow; however it should
be noted that CFs of 50% or more are exceptional.
It should also be noted that a WTG must cut out at wind speeds in excess of, typically, 25m/s,
depending upon turbine type.
In the sensitivity analysis the average wind speed is stepped from 6m/s to 16m/s.
3.4.3
WTG Availability
WTG availability is described in detail in Section 3.2.2. In the sensitivity analysis the availability is
stepped between 84% and 100%.
4
Results
The results below are based on the typical wind farm parameters used as a basis for the Round 3
offshore wind farm connection study main report (v1.0)
4.1
Example wind farm base parameters
The base model set-up for this example is as follows:
WTG
Technology
Wind Farm
Size (MW)
Connection
Cost per MW
(£k)
Installed WTG
Cost per MW
(£k)
Average Wind
Speed (m/s)
WTG
Availability (%)
Repower 5MW
1110
700
1,500
9.0
90
Table A1.1. Base model set-up
4.2
Example wind farm base results
For these input values, the optimal installed given is 112% of the connection capacity, as shown in
Table A1.2. This is based on the total WTG installed cost increasing for the extra WTG’s but the
total connection cost remaining at the 1110MW x £700k value. The revenue generated is
increased due to the additional wind turbines operating at low wind speeds. (Note: at high wind
speeds the additional WTGs will result in each WTG being slightly more constrained; this is
allowed for in the model).
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Size (%)
100%
112%
Total CAPEX (£m)
2442
2642
Lifetime Revenue (£m)
6,874
7,680
CAPEX/Lifetime Energy Generation (£/MWh)
29.84
28.89
222
249
44.18%
44.08%
WTG (units)
Capacity Factor (%)
Table A1.2. Size results comparison
As shown Table A1.2, using 249 WTG at a total cost of £2,642m instead of 222 WTG with a total
cost £2,442m, generates revenue of £7,680m against £6,874m. It is evident that the capacity factor
is only slightly reduced by the loss in energy for the electrical constraint (assuming 90% WTG
availability in each case). However, installing generation capacity up to 112 % of the connection
capacity results in a better CAPEX/Lifetime Energy Generation Figure of £28.89 per MWh against
£29.84 per MWh produced were 100% connection capacity installed.
This CAPEX/Lifetime Energy Generation Figure can be used to assess how project variables affect
an investment in order to determine the economically optimised model, and hence should not be
used in isolation.
It can be seen in Figure A1.5, the red line representing the CAPEX/Lifetime Energy Generation
Figure has a minimum value at 112 % of the connection capacity.
Figure A1.5. Trend of CAPEX/Lifetime Energy Generation Figure as installed capacity increases as a
percentage of connection capacity
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4.3
Sensitivity Analysis
For this analysis each of the parameters in Table A1.1 was varied in turn.
4.3.1
Ratio of Connection Costs to Installed WTG Costs (Cost Ratio)
Table A1.3 shows the analysis results for a range of cost ratios with the wind speed and WTG
availability remaining at the base set-up given in Table A1.1.
It is evident that as the installed cost of the WTG reduces against a fixed connection cost, the
CAPEX/Lifetime Energy Generation Figure also reduces assuming a significant overbuild is
desirable. For a cost of £0.35m per MW installed WTG and £0.7m per MW connection cost, 333
WTG (150% of connection capacity) can be installed instead of the 222 provided in Table A1.2 for
100% connection capacity.
However, as is evident from both Table and Figure A1.6, as the cost ratio increases there is an
asymptotic trend for the optimum size of the wind farm toward 111%.
WTG cost/connection cost ratio
0.5
1
1.5
2
2.5
Size (%)
150%
122%
113%
112%
111%
Total CAPEX (£m)
1360
1725
2094
2517
2933
Lifetime Revenue (£m)
8933
8080
7725
7680
7630
CAPEX/ Lifetime Energy Generation (£/MWh)
12.18
17.08
21.68
26.22
30.75
WTG (units)
333
271
251
249
246
Capacity Factor (%)
38%
43%
44%
44%
44.
Table A1.3. WTG installed cost sensitivity sample results.
In Figure A1.6, each line represents the CAPEX/Lifetime Energy Generation Figure for different
cost ratios between the installed WTG cost per MW and a fixed connection cost per MW of £0.7m.
Figure A1.6. CAPEX /Lifetime energy figure & installed capacity sensitivity to WTG installed costs
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4.3.2
Average Wind Speed
Table A1.4 shows the sensitivity analysis results for a range of average wind speeds with the WTG
installed cost and WTG availability parameters remaining at the base set-up given in Table A1.1.
As provided in Table A1.4, the possible percentage of installed power against connection capacity
ranges asymptotically from 147% at low average wind speeds (6m/s) to 111% at high wind speeds
(16m/s). Given that the typical mean wind speed for the North Sea is 9m/s, these results suggest
that the optimum size wind farm installed capacity is 112% of the available connection capacity. In
the scenario presented here, the recommendation would be that the number of turbines used for
the development should be 249 rather than 222 (100% of connection capacity). As the average
wind speed increases there is little change in the optimum size. If the mean wind speed is less
than 9m/s then the optimum size increases in order to maximise the utilisation of the available
connection capacity.
Wind speed
(m/s)
6
7
8
9
10
11
12
13
14
15
16
Size (%)
147
126
114
112
111
111
111
111
111
111
111
Total CAPEX
(£m)
3225
2875
2675
2642
2625
2625
2625
2625
2625
2625
2625
Lifetime
Revenue
(£m)
4325
5395
6444
7680
8795
9801
10651
11347
11900
12302
12574
CAPEX /
Lifetime
Energy
Generation
(£/MWh)
59.65
42.63
33.21
27.52
23.88
21.43
19.72
18.51
17.65
17.07
16.70
WTG (units)
326
280
253
249
246
246
246
246
246
246
246
Capacity
Factor (%)
19%
28%
36%
44%
50%
57%
62%
66%
69%
71%
73%
Table A1.4. Average wind speed sensitivity
It should be noted that the average wind speed is a characteristic of the site chosen for the wind
farm development; however, this model can be used to ascertain the level of enhanced installation
above the connection capacity required to maximise the economic benefit given the site
constraints.
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Figure A1.7. Sensitivity of CAPEX/Lifetime Energy Generation Figure & installed capacity to average wind
speed
4.3.3
WTG Availability
Table A1.5 shows the analysis results for a range of WTG availabilities with the WTG installed cost
and Average wind speed remaining at the base set-up given in Table A1.1.
Availability (%)
84%
86%
88%
90%
92%
94%
96%
98%
100%
Size (%)
119
117
114
112
109
107
105
103
101
Total CAPEX (£m)
2758
2725
2675
2642
2592
2559
2525
2492
2459
Lifetime Revenue
(£m)
8180
8028
7829
7680
7487
7343
7200
7060
6922
CAPEX/Lifetime
Energy Generation
(£/MWh)
26.98
27.16
27.33
27.52
27.70
27.88
28.06
28.24
28.42
WTG (units)
264
260
253
249
242
238
233
229
224
Capacity Factor (%)
44%
44%
44%
44%
44%
44%
44%
44%
44%
Table A1.5. CAPEX/Annual Energy figure & installed capacity sensitivity to average wind speed
The results in Table A1.5 show that as WTG availability decreases, the percentage of installed
power for a given connection capacity needs to increase to maintain similar CAPEX/Lifetime
Energy Generation Figures. However, for a 90% WTG availability, an installed capacity of 112%
provides the optimum CAPEX/Lifetime energy figure, as shown in Figure A1.8.
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Figure A1.8. CAPEX/Lifetime Energy Generation Figure against installed capacity for
various WTG availabilities
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5
Recommendations
This high level analysis presented here suggests that the optimum installed capacity for a fixed
connection capacity in terms of a CAPEX/Lifetime Energy Generation Figure appears to be around
112%.
It is therefore recommended that the installed capacity for the Round 3 wind farms used in this
report be set at 112% of the total power transfer capacity of the technology elements used in the
connection design.
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6
References
[1]
Danish wind industry association, www.windpower.com.
[2]
NOABL and NCIC wind speed data
[3]
North Hoyle Offshore Wind farm annual report, URN no. 08/P47, BERR
[4]
CERA: Offshore Wind Power Capital Costs Will Continue To Rise, Creating New
Challenges for European Renewable Energy Targets, CERA (Cambridge Energy
Research Associates), Press Release 28 May 2008,
www.cera.com/aspx/cda/public1/news/pressReleases/pressReleaseDetails.aspx?CID=9512
[5]
Atlas of UK Marine Renewable Energy
www.berr.gov.uk/files/file27763.pdf, Dec 2004.
1845 Appendix 01 OWF installed-connection capacity study v1-0.doc
Resources:
Technical
Page 13 of 13
Report,
Appendix 2 : HVAC cable reactive compensation analysis methodology
A power systems model of a nominal 275kV offshore-onshore alternating current (AC) grid interconnection from a proposed 330MW (derived from the manufacturer’s maximum power rating) point
of supply (POS) to the onshore point off common coupling (PCC) was developed in PSS/SINCAL
V5.4. This model was used to assess at a high level the maximum feasible length of three-core
subsea AC cable that could be deployed before the combined issues of active power losses and
reactive power charging capacitance reduced the collector cables useful power carrying capacity to
zero. Figure A2.1 illustrates the power system model.
I61
-316.82 MW
-765.35 MVAr
100.00 %
0.00 °
316.82 MW
1
765.35 MVAr
-327.71 MW
-455.05 MVAr
112.41 %
2.43 °
327.71
MW
2
328.69 MVAr
-330.00 MW
108.00 MVAr
115.10 %
5.16 °
LO57
330.00 MW
-108.00 MVAr
Figure A2.1: PSS/SINCAL power systems model
The following assumptions have been made regarding the model:
•
The collector cables from the offshore POS to the landfall transition pit and from the landfall
transition pit to the PCC are equal in length
•
Import of reactive power is defined as inductive and export of reactive power is defined as
capacitive where 0.95 power factor equates to the import or export of 108MVAr of reactive
power
•
The offshore wind farm is capable of importing 108MVAr of reactive power at the POS during
maximum active power export to partially offset the cable charging current
•
The PCC is controlled to a nominal voltage (275kV)
•
The maximum permissible variation of voltage from nominal is ±10% of nominal voltage
1845 Appendix 02 HVAC cable reactive compensation methodology v1.0.doc
Page 1 of 2
•
The grid at the proposed PCC is strong, i.e. the fault level from the grid is 10 times the fault in
feed from the proposed 330MW infeed, in order to minimise voltage variations
The reactive power compensation (RPC) to compensate for cable charging capacitance was
assessed under the following conditions:
•
No additional RPC
•
RPC of equal quantity installed at the PCC and POS (50/50 split)
•
RPC of equal quantity installed at the PCC, landfall transition pit and POS (33/33/33 split)
Initial approximate sizing of the RPC requirement was determined from Equation 1 where Qreq is
reactive power, C is the cable capacitance (µF) per km, l is the cable length in km’s, V is the
operating voltage of 275kV and ω is the angular frequency of the supply in radians. It is important to
note that this does not consider the presence of voltage drop due to resistive losses and also series
inductance of the cable. Further optimisation of the RPC was performed manually to produce near
zero reactive power transfer to the PCC.
Equation 1: Sizing of RPC
Qreq = ωClV 2
The cables average current flow (kA) and apparent power capacity (MVA) were applied as
constraints to determine the cables useable capacity. These are defined as follows:
•
Average current flow – The current carrying capacity of the conductors’ cross-sectional area
is the limiting factor. If this is exceeded the heat produced over a prolonged period of time
would cause damage to the conductor insulation possibly causing a total dielectric failure.
Figures are shown as an average of the current flows observed at different points in the
cable. Indication has been given in Table 4 of the main report to cases where peak current
flow exceeds the cables current capacity
•
Apparent power capacity - This considers the conductors current carrying capacity with
respect to transmission voltage. If the transmission voltage exceeds the design withstand
voltage of the cables dielectric for a significant period of time it will cause the dielectric
breakdown causing possible short circuits in the dielectric or intermittent breakdown of the
dielectric due to charging current producing transient interference
The results of this analysis are presented in Table 4 of The Round 3 Offshore Wind farm Connection
Study main report (v1.0).
1845 Appendix 02 HVAC cable reactive compensation methodology v1.0.doc
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