ES Chapter 5 - Galloper Wind Farm

Transcription

Galloper Wind Farm Project
Environmental Statement – Chapter 5: Project Details
November 2011
Document Reference – 5.2.5
Galloper Wind Farm Limited
Document title
Environmental Statement – Chapter 5:
Project Details
Document short title
Document Reference
5.2.5
Regulation Reference
APFP Regulations 5(2)(a)
Version
Status
Date
Final Report
November 2011
Client
Galloper Wind Farm Limited
Drafted by
Checked by
Date/initials check
GWFL Approved by
Date/initials approval
Galloper Wind Farm ES
14
Project name
Reference
Final Report
9V3083/R01/303424/Exet
GWFL & Royal Haskoning
Various
RS PT
30.05.2011
Kate Harvey
KH
18.11.2011
-i-
9V3083/R01/303424/Exet
November 2011
CONTENTS
Page
5 PROJECT DETAILS
5.1 Introduction
5.2 Outline Project Description
5.3 Site Location
5.4 Wind Resource
5.5 Offshore Physical Characteristics
5.6 Wind Farm Flexibility and Layout
5.7 Wind Turbine Generators
5.8 WTG Support Structures
5.9 WTG Support Structure Ancillary Equipment
5.10 WTG Foundation Systems
5.11 Ancillary Infrastructure
5.12 Inter, Intra-array and Export Cables
5.13 Cable Landfall
5.14 Landfall and Other Onshore Drilling Works
5.15 Onshore Transition Bays
5.16 Onshore Cabling
5.17 Onshore Substation
5.18 Landform
5.19 Sealing end compounds, gantries and overhead wires
5.20 Other onshore infrastructure
5.21 Summary of onshore infrastructure permanent and
temporary footprint
5.22 Project Programme
5.23 Offshore Pre-construction and Construction
5.24 Onshore Construction
5.25 Commissioning
5.26 Offshore Operations and Maintenance
5.27 Onshore Operations and Maintenance
5.28 Repowering
5.29 Decommissioning
5.30 References
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5
PROJECT DETAILS
5.1
Introduction
5.1.1
This Chapter of the Environmental Statement (ES) presents the details of the
Galloper Wind Farm (GWF) scheme and describes the construction,
operation, maintenance and decommissioning components of the project,
which would primarily comprise:

Wind turbine generators (WTGs) and supporting tower structures;

WTG foundations with associated support and access structures;

Offshore platforms to support offshore substation(s), potential
collection station and accommodation facilities;

Meteorological mast(s);

Subsea inter and intra-array and export cables;

Cable landfall and reception pits;

Onshore transition bays;

Onshore cabling from the landfall to the GWF substation;

Directional drilling under roads, foreshore habitats and potentially
other cables;

132kV onshore GWF compound and 132kV/400kV onshore
transmission compound, which together are referred to as the “GWF
substation”;

Creation of a landform around three sides of the GWF compound and
other landscaping proposals;

132kV connection between the two adjacent compounds;

Onshore cabling from the 132kV/400kV transmission compound to the
sealing end compounds;

Transmission sealing end compounds adjacent to existing electricity
transmission towers (pylons); and overhead line connections to the
towers;

Onshore cabling from the 132kV/400kV transmission compound
connecting into the existing Greater Gabbard Offshore Wind Farm
(GGOWF) 132kV cables (which run from Sizewell B to the GGOWF
substation);

Alterations to existing electricity transmission towers;

Relocation of an existing telecommunications mast;

Temporary works and laydown areas;

Permanent and temporary access roads; and
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
5.1.2
Service corridors, including telecommunications, water and connection
to the local electricity network.
Plot 5.1 on the following page shows the high level components of GWF.
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Plot 5.1 Galloper Wind Farm overview
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5.1.3
The details provided in this Chapter are based on the latest knowledge and
information available at the time of production of this ES. In some cases,
specific information relating to GWF is not available (for example, the exact
method of construction will not be confirmed until contracts have been
tendered and awarded). As such, construction methodology provided herein
is based on similar projects, particularly GGOWF. Complex and extensive
detailed design and procurement processes take place over a lengthy period
closer to construction on a scheme of the scale of GWF.
5.1.4
For the purposes of the consent documentation, Galloper Wind Farm Limited
(GWFL) has therefore provided a range of possible options with regard to
certain aspects of construction methodology and project components. GWFL
has provided sufficient flexibility in this project description to ensure that all
realistic development scenarios are captured within this ES. Furthermore, it
is noted that the design information provided is representative of the
maximum scenario (in terms of size, number, depth etc). These two facets
serve to ensure that the assessments made within the ES are on a scenario
that represents the upper limit (or realistic worst case) of what may actually
take place (as discussed in Chapter 4 EIA Process). It is noted that whilst
these upper ranges have been assessed, GWFL may seek to develop less
than these maximum values once all considerations have been introduced
and evaluated in the final design.
5.2
Outline Project Description
5.2.1
As outlined in Chapter 1 Introduction, the GWF project comprises a
development of up to 140 WTG, with a maximum capacity of up to 504MW
encompassing an area of 183km2 comprising up to three distinctly identifiable
areas and inter-array cabling (Development Areas A, B and C – see Figure
5.1).
5.2.2
Details of the project components considered for assessment are provided
throughout this Chapter, along with descriptive information on the methods
associated with the construction, operation and decommissioning of these
components. This information has been used to inform the technical
chapters contained within this ES and is considered to represent the Project’s
‘development envelope’.
5.2.3
The technical elements of the Project give rise to the potential for multiple
options in accordance with the Project design parameters (e.g. for WTG and
foundations). The implications for the ES are discussed within Chapter 4
under the Rochdale Envelope principle and in Section 5.6 of this Chapter.
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5.3
Site Location
5.3.1
Located approximately 27km from the nearest point on the Suffolk coast, the
proposed GWF project lies immediately adjacent to the existing GGOWF
project (see Figure 5.1).
5.3.2
The export cable corridor will connect from the offshore site to a landfall
south of Sizewell on the Suffolk coast, running adjacent and to the north of
the existing GGOWF export cables (Figure 5.1). At the approach to the
landfall the GWF cables will move closer to each other and to the GGOWF
cables to maximise the separation from properties to the north.
5.3.3
The onshore GWF substation will comprise a new GWF 132kV compound
and also a new 132kV/400kV transmission compound, as described in
paragraph 5.1.1. The two compounds will be located alongside each other
and together are referred to as the GWF substation.
5.3.4
The GWF substation is located near Sizewell, approximately 1km inland on
the Suffolk coast. It will be situated to the north of Sizewell Gap, immediately
to the west of the existing GGOWF substation site (see Figure 5.2).
5.3.5
The onshore transition bay(s) will be located in land to the south of Sizewell
Gap with onshore cabling from there, crossing the existing GGOWF cables,
to the proposed GWF substation. There would be a need for additional
cabling between the transmission compound and the sealing end compounds
and also between the transmission compound and the existing GGOWF
cables and Leiston A substation (see Figure 5.2).
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5.4
Wind Resource
5.4.1
To minimise initial intrusive works, it was established that the current
meteorological mast located on the GGOWF site (4km from the western tip of
GWF Area A) presented current and historic data which would be
representative of the GWF site.
5.4.2
The first measurements were recorded by the mast in August 2005. The
mast continues to collect data and to date has recorded over five years of
data. Measurements are made at a range of heights between 42.5m and
86m above mean sea level (amsl).
5.4.3
Using the dataset from August 2005 to July 2010, a mean wind speed of
9.4m/s was calculated at 86m amsl (which is taken as indicative of conditions
around hub height), using the mean of monthly means method to account for
seasonal variation.
5.4.4
The wind direction over this period was predominantly from the southwest
(Plate 5.1).
Plate 5.1 Long term wind rose for GGOWF and GWF
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5.5
Offshore Physical Characteristics
5.5.1
GWFL has developed a sound appreciation of the physical conditions
(bathymetry, seabed sediments and shallow geology) of the GWF site. This
has been achieved by site investigations including a geophysical survey
campaign and utilising the detailed knowledge gained from developing the
adjacent GGOWF project. Chapter 9 provides a detailed account of these
physical parameters.
5.5.2
The data is sufficiently detailed to enable GWFL to have confidence that the
conditions present are conducive to the development of an offshore wind
farm and associated cable infrastructure. Water depths vary significantly
across the development area which gives cause to consider multiple
foundation solutions to accommodate the different depths, turbine types and
ground conditions as presented in Section 5.10.
5.5.3
The Outer Gabbard Bank (an open shelf linear tidal sand bank) is within Area
A (see Figure 5.1). Construction of WTGs, platforms or meteorological
masts will be avoided on the main sand bank on account of a combination of
engineering and environmental factors. For the same reasons any intraarray cabling will be kept to the minimum required in this area.
5.5.4
The current level of information is sufficiently detailed to enable a robust EIA
to be undertaken. However, additional survey will be required to facilitate
detailed design post-consent in key areas including:
 Foundation structures and scour protection (if required);
 Subsea cable installation within the wind farm site and along the
export cable route; and
 Any jack-up vessel operations (vessels with legs that can be lowered
to the seabed allowing the hull of the vessel to be raised clear above
the water).
5.5.5
With the adoption of a standard Front End Engineering Design (FEED)
approach it is anticipated that these investigations will be conducted prior to
the start of construction and would include:
 Boreholes at a select number of foundation locations and along the
export cable route;
 Cone penetrometer testing (CPT) at a select number of foundation
locations and along the export cable route;
 Vibrocore sampling along the export cable route;
 Plough trials along the export cable route;
 Pre-lay grapnel runs along the export cable route;
 Unexploded Ordnance (UXO) survey; and
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 Investigation of any obstructions to construction that are identified
through geophysical survey.
5.5.6
Geotechnical investigations both within the wind farm site and cabling areas
would be to a depth below the design penetration depth of the foundation
options and potential cable burial depths to give confidence in results, and
the subsequent design and construction approach.
5.5.7
Geophysical survey investigations will be carried out in accordance with
relevant Maritime and Coastguard Agency (MCA) guidance (MGN 371) and
International Hydrographic Organisation (IHO) standards (IHO Order 1a) and
encompass the project footprint. Further pre-construction survey may
include higher coverage (200%) multibeam surveys around each foundation
location followed by a Remotely Operated Vehicle (ROV) inspection if
anything relevant for UXO assessment is identified. Other investigations may
be undertaken for scour assessment.
5.5.8
Further detail of this pre-construction activity (in terms of vessel types and
durations) is provided in Section 5.23.
5.6
Wind Farm Flexibility and Layout
5.6.1
This Chapter frequently references the draft Development Consent Order
(DCO) included with this application. The purpose of doing so is to identify,
in each fundamental element of the project, the flexibility that will be
permitted in the consent. As such each section provides a summary table
relating to the DCO provisions and requirements, noting where flexibility is or
is not being permitted. The draft DCO includes a draft deemed marine
licence. All the DCO provisions and requirements in the summary tables are
also contained in the draft marine licence. In addition the marine licence has
other conditions concerning the submission of detailed matters for approval
by the MMO post-consent and pre-construction. Where relevant these are
also referred to in the summary tables.
No offshore turbine layouts are submitted for approval with the draft DCO as
complete flexibility will be required to ensure the scheme can be designed to
a deliverable form post-consent, once detailed ground investigation and
design optimisation work has been undertaken and tenders are received.
5.6.2
Any turbine layouts included in the body of this ES or its Appendices are
solely for the purpose of informing the reader as to the fundamental flexibility
permitted and are not illustrative of any probable layout, over and above any
other potential permutation.
(Post-consent, procurement and design
optimisation, a final proposed layout will be submitted for approval under the
deemed marine licence. Any such layout will be able to take advantage of
the flexibility summarised below, as long as it complies with the relevant
limitations, requirements and conditions in the DCO and marine licence.)
5.6.3
Key flexibility is included in the following areas:
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 Total number of turbines (subject to the maximum 504MW limit);
 Location of turbines within the array areas;
 Type of turbines and their mix in the development;
 Extent to which any array area (A, B or C) is developed in part, in full,
or not at all;
 The density to which any one area, or part thereof, is developed with
turbines, i.e. turbine densities across the site may, or may not, be
consistent;
 Mix and areas of use of different foundation types within the array
areas;
 Variation of detailed design within any of the four identified foundation
types (monopile, space-frame, gravity base, suction monopod);
 Number and routing of subsea cables (except where constrained to
the defined inter-array corridor between array areas A, B and C or in
the export cable corridor);
 Number of onshore cables and transition bays;
 Detailed arrangement within the GWF compound of the onshore
substation of the Sealing End Compounds.
5.6.4
Whilst the above flexibility is permitted on turbine layouts, in reality the
maximum turbine population of the wind farm for any given turbine size(s) will
be primarily driven by optimising the space between WTGs to gain maximum
effect from the wind resource and by locating turbines based on the impact of
foundation feasibility (both engineering and commercial). For practical
considerations and turbulence, the WTGs will be spaced at a minimum of 8
rotor diameters apart in the prevailing wind direction (± a minimal permitted
offset) based on the smallest 107m diameter turbine permitted. At 90
degrees to the prevailing wind the WTGs would be spaced at a minimum of 6
rotor diameters apart (termed in this Chapter as a ‘minimum 8 by 6 spacing’),
again based on the smallest permitted turbine rotor diameter. This equates
to a minimum spacing, for all permitted turbine rotor diameters, of 856m by
642m. However any spacing greater than 856m by 642m is permitted and
the final decision on turbine spacing is decided during scheme optimisation
post-consent.
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5.6.5
WTG MW capacity is driven by swept area (determined by blade length) and
internal generating components. Hence different marketed turbines of the
same or similar rotor diameter are unlikely to have the same MW capacity.
The WTG under consideration in this ES range from 107m to 164m rotor
diameter and hub height 79m to 120m. Turbines sitting in this range have
different technical and dimensional characteristics but the site would not
incorporate any more than 140 WTGs or have a greater total output than
504MW.
5.6.6
Chapter 4 explains the Rochdale Envelope ‘worst case’ approach to
assessments in this ES, which ensures consideration of the entire range of
flexibility outlined above. Figures 5.3 to 5.5 show illustrative layout
examples of schemes lying within the 140 WTG and 504MW constraints for
example rotor diameters of 107m, 120m and 150m and also gives an
indication of the different aspects that may vary. Commentary on these
figures is given further below. Any final layout will have to respect the
physical, environmental and human information obtained for the site to date
and take into account the known constraints posed by these parameters. A
number of purely illustrative layouts have been used to inform the relevant
studies carried out within the EIA for the GWF project; supplemented by a
subsequent EIA review to ensure that flexibility presented in the application
would not result in any change to the likely significant effects identified from
the illustrative layouts. Examples of constraining effects on layouts include:
 Water depths;
 Seabed geology;
 Ship wrecks and other obstructions;
 Wind resource assessment;
 Stakeholder feedback;
 Proximity to the future East Anglia Offshore Wind Farms; and
 Proximity to the existing GGOWF.
5.6.7
As a result, the final layout would not be fixed until FEED (Front-End
Engineering Design) work and tendering has been completed post-consent.
Figures 5.3 to 5.5 should not be taken as to demonstrate or imply any
potential future layout or distribution of turbines that may be sought postconsent.
5.6.8
The draft DCO does not contain reference to any layout plans for the offshore
infrastructure, but is bound by the application boundary and array areas
within which the infrastructure can be located, together with various
restrictions (e.g. maximum number of turbines, maximum blade tip height
etc).
5.6.9
In summary, readers should be aware of the level of flexibility permitted in
this application and its necessity. Fundamental variations are outlined above
and could in some potential layouts result in large areas of the site remaining
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undeveloped or developed at varying densities, with varying turbine or
foundation types. On the other hand, the final layout may be a regular grid
across the full array areas, as is the case with the GGOWF as-built layout
(also captured in Figures 5.3 - 5.5). The ‘worst case’ approach to
assessment of such flexibility is discussed in more detail in Chapter 4.
Illustrative figures
5.6.10
Figures 5.3 to 5.5 below show some illustrative examples of how a wind
farm may be laid out, and some of the aspects that might vary when the
scheme is optimised.
5.6.11
Figure 5.3 shows a 107m rotor diameter model with 90 WTG in Area A, 38 in
Area B and 12 in Area C, achieving the maximum 140 turbines. In doing so
the WTG have been spaced more closely, although not consistently, within
Area A than they have been in Area B. In Area B the WTG have been
spaced some distance apart, well beyond the minimum 856m x 642m
spacing. In Area A both a sand bank and palaeochannels have been
avoided, and the scheme utilises a substation in each of the three Areas.
5.6.12
Given that the spacing of Area A still does not reduce to the minimum 856m x
642m, it would be quite feasible to increase the intensity in Area A still further
and either decrease the spacing in Area B or C, or not have turbines (or
substations) in either Area B or C at all.
5.6.13
Figure 5.4 shows a larger 120m rotor diameter, spaced in a generally more
consistent manner than Figure 5.3. The majority of the development area is
used, although the minimum spacing is not sought. Three substations are
still utilised, however Area C does not warrant a substation in its own right, or
the third southerly substation might ultimately be proved unviable in such a
scenario. 140 turbines are shown, as in Figure 5.3, but there is a different
balance in turbine numbers between Areas A and B.
5.6.14
Figure 5.5 shows a 150m rotor diameter distributed sparsely, and less
regularly (particularly in Area B). Parts of Area C remain unused, either due
to electrical inefficiency in this particular layout form, or other considerations.
Given that the layout does not approach the minimum 856m x 642m it would
be quite conceivable to decrease the spacing in one Area or utilise unused
areas and remove large proportions of another Area. Overall Figure 5.5
includes 72 turbines comprising 48 in Area A, 19 in Area B and 5 in Area C.
5.6.15
All three Figures 5.3 to 5.5 assume a 504MW maximum capacity is
achieved, assuming that the 107m and 120m rotor diameter are 3.6MW and
the 150m rotor diameter is a 7MW machine. It is equally possible that the
optimisation process would find that a lower overall MW output is the only
viable solution, or results in greater overall energy capture. Reducing the
MW capacity could be achieved by any of the following:
 Removing turbines from deeper or more constrained areas, potentially
creating a significantly less regular arrangement;
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 Increasing spacing between turbines across a similar area;
 Removing blanket areas of the scheme from the construction
proposal;
 Mixing turbine types; or
 Any combination of the above.
5.6.16
All of the above considerations, whether for a full 504MW scheme or less
would also be open to variation of the number of substations,
accommodation platform and collector station.
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5.7
Wind Turbine Generators
Concept summary
5.7.1
WTG consist of three primary components (see Plate 5.2):
 The tower;
 The nacelle; and
 The rotor.
Plate 5.2 WTG component overview
Source: The Crown Estate (2010)
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WTG tower
5.7.2
The WTG tower is the component which supports the rotor and therefore
gives it the necessary height. The structure is likely to consist of up to four
tapering steel tubular sections, which are lifted into place and secured
together by bolting. Each tower section will arrive on location with preinstalled internal fittings, thus aiding the secondary installation phase.
5.7.3
The bottom tower section is bolted via a flange to the TP. Similarly the top
tower section will be flanged to facilitate the connection with the nacelle
component.
The nacelle
5.7.4
The nacelle houses the electro-mechanical elements of the WTG, or more
simply a machine that can turn rotational motion into electrical energy.
Depending on the WTG supplier, additional equipment such as the WTG
transformer could also be housed in the nacelle.
The rotor
5.7.5
The rotor is the device which, through circular motion, extracts the energy
from the wind. Increasing the blade length allows more energy to be
extracted from the passing wind through a greater ‘swept area’. The blades
can be feathered or twisted (i.e. changing their pitch) to maintain a particular
speed. Three-bladed rotors are the most common type and will be used on
the GWF project.
WTG manufacturing and transportation
5.7.6
The primary components of the WTG are typically fabricated in smaller units
for transportation purposes, for example each blade for the rotor is
manufactured individually.
5.7.7
The method of transportation to site depends on the WTG manufacturer’s
recommendations, the type of installation vessel and the timing of
installation.
As an example, the GGOWF WTG components were
transported to the offshore location then lifted into position, as opposed to
pre-assembly onshore of the tower and nacelle, followed by shipment to site.
Fluids and oils
5.7.8
The volume of fluids and oils required by a WTG is greatly dependent on the
drive train and pitching technology of the specific WTG. If the oil in the
nacelle (i.e. the gearbox and hydraulic tanks) were to leak under any
circumstances then it would most likely leak down the walls of the tower, on
the inside, and would accumulate under the access platform at the base of
the transition piece where it would be contained.
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5.7.9
During operation the fluids may be under high pressure, and mechanical
failures could lead to high pressure fluid release. In such an event the
machine will shut down automatically due to low pressure/ low level alarms
etc. A hydraulic failure in the hub will have a similar outcome.
5.7.10
WTGs are designed to prevent any significant accidental leakages of such
fluids and oils, as the bottom of the tower/ transition pieces are typically air
tight with sufficient containment incorporated into the structure to prevent
accidental fluid release. Furthermore, containment will also be included in
the design and construction of the nacelle and the top tower platform. All of
the main bearings including the slew, hub and pitch will also be equipped
with grease catchers.
WTG installation
5.7.11
Installation methods for WTGs vary and include assembly of the turbine
tower, nacelle and rotors individually whilst at sea, through to transfer of
complete turbines from land. Most typically the towers are mounted vertically
on a dedicated heavy lift installation vessel and one or more blades joined to
the rotor hub before shipment, with the final blade(s) installed once the tower
and rotor are in place.
WTG operational noise
5.7.12
When a windfarm is operational the main source of underwater noise is
mechanically generated vibration from the turbines transmitted into the sea
through the structure of the support pile and foundations (Nedwell et al.
2003). Subacoustech (Nedwell et al., 2007) has undertaken a review of four
operational wind farms (North Hoyle, Scroby Sands, Kentish Flats and
Barrow). The available data indicated that the noise generated by a working
turbine is very low and significantly lower than the noise created during
construction by piling. However, while construction noise may only span a
period of a few months, operational noise will span the lifetime of the
windfarm (Nedwell et al., 2007).
5.7.13
The study findings revealed that the level of noise from operational
windfarms was very low and was not considered to pose any risk to fish and
marine mammals (Nedwell et al., 2007). In some instances, operational
noise could be recognised by the tonal components caused by rotating
machinery and by its decay with distance. However, the noise generated by
the operating WTG, even in the immediate vicinity, only dominated over the
background noise in a few limited bands of frequency and equated to a rise
of only a few dB above background noise levels. In some cases, the tonal
noise caused by the WTG was dominated by the tonal noise from distant
shipping (Nedwell et al., 2007).
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WTG options
5.7.14
There are many WTG models of varying rotor diameters which are, or may
become, available for use on GWF. Regardless of the chosen turbine, the
wind farm will consist of a maximum of up to 140 WTGs, with an output not
exceeding 504MW, and each individual turbine rotor diameter ranging from
107m to 164m. These rotor diameters represent WTGs in the order of
3.6MW to 7MW capacity based on currently available models, although
individual MW capacity limits are not proposed. All options will have a
minimum clearance distance, to the lowest point on the passage of the blade
tip, of 22m above mean high water springs (MHWS).
5.7.15
WTGs normally operate within a predetermined range of wind speeds,
typically starting at 3.5ms-1 and producing their maximum power at
approximately 12ms-1. WTGs typically shut down at wind speeds greater
than 25ms-1, in order to avoid damage.
5.7.16
The final decision on the WTG type(s) utilised by GWF will depend on the
WTGs available in the market place at the time of procurement, the
economics associated with the manufacture, transportation and installation
of the available options, and the outcome of detailed FEED and optimisation
studies post-consent, and the parameters (maximum blade tip height etc)
permitted in the DCO. Table 5.1 provides indicative information concerning
the typical dimensions and characteristics of three different generic blade
rotor lengths. The table is intended to show the relative scale of three
different generic turbines and the general relationship between their
parameters, to give an appreciation of the kind of flexibility the consent is
intended to allow for.
For the avoidance of doubt, the worst case
assessment in the EIA has not been limited to these generic turbine
descriptions.
Table 5.1 Summary of typical relationship/differences between WTG parameters for
different sizes
WTG detail
107m rotor
120m rotor
164m rotor
Minimum clearance above
22m
22m
22m
140
140
84*
Hub height (ma LAT)
79.5m
86m
120m
Maximum tip height (ma
133.1m
146m
195m**
MHWS
Maximum number of WTG
likely in wind farm (based
on typical nameplate
capacity)
LAT)
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WTG detail
107m rotor
120m rotor
164m rotor
Rotor diameter
107m
120m
164m
3-5ms-1 cut in,
3-5ms-1 cut in,
3-5ms-1 cut in,
25ms-1 cut out
25ms-1 cut out
25ms-1 cut out
Maximum rotor speed
13rpm
13rpm
12.1rpm
Maximum tip velocity
73ms-1
81.7ms-1
103.9ms-1
Total project swept rotor
1.264km2
1.583km2
1.521km2
3 - 3.6MW
3.6 - 4MW
6 - 7MW
Cut in/out speed
area
Typical expected
‘nameplate’ MW rating for
this order of rotor
diameter (for assisting
comprehension in relation
to the total 504MW
capacity only)
* Based on 6MW capacity per turbine, likely to be the lowest ‘nameplate’ capacity for a large
diameter rotor such as this. Total number would reduce for a higher MW capacity
** Note that placing a 164m on a 120m hub would breach the 195m tip height (and hence
be non-compliant with the DCO parameters), however the example is used to understand a
turbine combining all maxima. In reality, either the hub height or the rotor diameter would
have to reduce until a tip height of 195m was achieved.
5.7.17
The table below identifies the key controls imposed by the draft DCO and
deemed Marine Licence with respect to this section on WTGs. The table
also identifies what flexibility is therefore permitted within each constraint.
This approach is followed throughout this Chapter, providing a summary to
each subsequent section. DCO tables are referenced separately to other
tables, preceded with “DCO.”.
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Table DCO.1
Section: WTG parameters
Ref
DCO constraint
wording
Sch1, An offshore wind turbine
Pt 1,
generating station with a
(1)(a)
gross electrical output
capacity of up to
Key flexibility arising
within DCO constraint
Comment
Any capacity below
A minimum Requirement
504MW or number below
would be unenforceable.
140 turbines is permitted,
In practice most UK wind
regardless of turbine size
farms have been built out
504MW comprising up
to their full MW capacity
to 140 wind turbine
generators
Any ‘nameplate’ MW
Capacity is a function of
capacity of turbine is
rotor diameters within
permitted
limited variations of yield,
hence the type of turbine
is fundamentally
constrained by rotor
diameter which is a more
accurate measure of
impacts.
Sch1,
Pt 3,
(3)(a)
No wind turbine
All maximum tip heights
Whilst permitting a blade
generator forming part
below 195m are
tip below the minimum
of the authorised
permitted, including below
135m considered in the
development shall:
135m
assessments, a minimum
is achieved by a
exceed a height of 195
combination of the
metres when measured
minimum blade diameter
from LAT to the tip of
and minimum clearance.
the vertical blade
Sch1,
Pt 3,
(3)(b)
No wind turbine
Hub height may be at any
In reality the minimum hub
height at or below 120m
height is fixed by a
of the authorised
combination of minimum
development shall:
blade diameter and
minimum clearance
exceed a height of 120
metres to the height of
the centreline of the
generator shaft forming
part of the hub when
measured from LAT
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Sch1,
Pt 3,
(3)(c)
No wind turbine
Any rotor diameter at or
between 107m and 164m
of the authorised
is permitted
development shall:
Multiple turbine types may
In practice, more than two
exceed a rotor diameter
be used in the
turbine types is unlikely for
of 164 metres, or have a
development
commercial reasons
No wind turbine
Irregular layout across the
Where turbines are built, a
entire offshore
reasonably regular layout
of the authorised
development area, or any
is likely in practice, though
development shall:
part thereof, is possible
a perfect pattern of rows is
rotor diameter of less
than 107 metres
Sch1,
Pt 3,
(3)(d)
unlikely in any one area
be less than 642 metres
from the nearest WTG
Large parts of the
in either direction
development area may
perpendicular to the
not be used at all
approximate prevailing
wind direction or be less
than 856 metres from
the nearest WTG in
either direction which is
in line with the
No limit on how many
turbines can be placed in
each array area, as long
as minimum separation
distances are maintained
approximate prevailing
No minimum separation
wind direction
distance is imposed
between turbines and
other structures
The prevailing wind
The prevailing wind
direction is not defined,
direction is unlikely to vary
allowing the minimum
significantly from that
distance of 642 metres
shown in this Chapter
from the nearest WTG to
based on existing
be applied in any desired
measurements and
direction
inevitably promoters will
seek the largest spacing
in the prevailing wind
direction
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Any minimum blade tip
The minimum distance is
separation distance
sought by promoters since
above MHWS greater
this distance has been
than 22m is permitted
agreed with the Royal
Yachting Association
(RYA) for all offshore wind
farms.
Sch1,
Pt 3,
(3)(e)
No wind turbine
Any clearance above 22m
is permitted, although in
of the authorised
reality turbines seek to
development shall:
minimise clearance to
have a distance of less
than 22 metres between
the lowest point of the
reduce increases in tower
height and foundation
loads
rotating blade of the
wind turbine and MHWS
5.8
WTG Support Structures
Transition piece
5.8.1
The TP connects the foundation to the WTG. The TP serves several
different purposes as it can be used to house the necessary electrical and
communication equipment and provide a landing facility for personnel and
equipment from marine vessels.
5.8.2
For space-frames and GBS foundations the TP is often integrated with the
foundation at fabrication stage. TP are primarily used for monopiles where
the secondary structures cannot be located on the monopile (as it is driven)
and, as such, need to be installed on a TP that also assists the achievement
of verticality via adjustment permitted in the grouted connection.
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Transition piece: monopile
5.8.3
The main shaft of the TP (Plate
5.3) may be slightly larger in
size than the foundation pile
(up to 7.5m) and would be fitted
once the foundation is in place.
The TP is craned into position
over the exposed top and
carefully lowered into position.
Once located in situ on top of
the foundation a jack system is
used to level the TP. A level
top would be essential as the
WTG tower section is bolted
directly onto the TP.
5.8.4
To ensure the TP remains in a
level position, grout is applied
between the foundation and TP
to bond the structures together
and to provide a load bearing
connection.
5.8.5
The
external
corrosion
protection system used for the
TP will be as described in detail
for the foundation systems in
Section 5.9.
Plate 5.3 Typical monopile transitional piece
Source: www.kentishflats.com
Transition piece: space-frame
5.8.6
The TP associated with a space-frame structure (see Plate 5.4) is shorter
then those used on the other types of foundation structures, primarily as the
space-frame structure extends far enough above sea level and would also
be fitted with landing facilities. The TP can be welded into position onshore
prior to the space-frame being transported to its offshore location.
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Plate 5.4 Typical space-frame transition piece
Transition piece: gravity base structure
5.8.7
A gravity based structure may or may not be designed to accommodate a
TP. If a TP is to be used the design and installation process is identical to
the monopile TP. It should be noted that if this foundation system uses a TP
then less seabed levelling preparation is required as the jack system
between the GBS and TP can be used to level the top surface.
5.8.8
If no TP is used then the GBS extends further above sea level and requires
landing facilities and auxiliary equipment to be installed.
5.8.9
The WTG tower is connected directly onto the GBS structure via a flanged
connection. With this option all the necessary electrical equipment is
housed within the WTG tower.
Corrosion projection
5.8.10
The corrosion protection utilised for the TP section is likely to be in line with
that considered for the foundation options, see Section 5.10.61.
Electrical equipment
5.8.11
The electrical equipment contained within WTG is typically housed within
either the TP or the base of the tower, and comprises:
 Converters or power electronics;
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 Low voltage (LV) circuit breakers;
 Transformers (occasionally, for instance a Vestas WTG, houses the
transformer in the nacelle rather than the TP); and
 Medium voltage (MV) circuit breakers.
5.8.12
Cabinets are also installed to house control equipment, telecoms and
emergency power supply units.
5.8.13
The electrical equipment requires a controlled atmospheric environment,
along with the regulated dissipation of the heat generated. Therefore,
dehumidifiers and air conditioning units are also installed to ensure a
suitable atmosphere is maintained.
5.8.14
The precise composition of electrical equipment, housing and its location
(within TP or tower) depends on the WTG selected.
5.9
WTG Support Structure Ancillary Equipment
Introduction
5.9.1
This section details the ancillary equipment that is normally located
externally on the WTG foundation and the transition piece.
5.9.2
The ancillary equipment is defined as:
 J-tubes;
 Access and rest platforms;
 Access ladders;
 Boat access system; and
 Corrosion Protection Systems.
J-tubes
5.9.3
J-Tubes comprise the metal tubes that protect the inter or intra-array
electrical cables as they travel up the foundation structure to the TP. The
metal tubes at the bottom of the foundation structure are generally curved to
support each inter or intra-array cable as it transitions from a horizontal to a
vertical position. Each J-tube houses one inter or intra-array cable, therefore
more then one J-tube would be required per foundation structure to facilitate
the incoming and outgoing array cables.
5.9.4
The J-tube can extend from the seabed all the way up the foundation
structure to the TP. If the foundation structure is a monopile or space-frame
type the J-tubes can be housed externally or internally to the structure. Jtubes located inside the foundation structures have an additional level of
protection.
External attachment of J-tubes is more likely with GBS
foundation structures.
Boat landing system access
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5.9.5
The design of boat landing facilities, access ladders and subsequent
platforms is driven by the type and largest size of boat anticipated to be used
in the maintenance programme. It would be reasonable to assume that
marine grade floodlights will be fitted to illuminate the boat landing as
required during hours of darkness. Typically the lights are controlled from
the wind farm control room.
Access ladders
5.9.6
Experience on GGOWF has shown that two vertical access ladders (rather
than one) are required and it is anticipated that a similar system would be
used on the GWF project where TP solutions are adopted. The ladders are
approximately 600mm wide with rungs at 300mm vertical intervals. To
protect the lower ladder a permanent fender system would be located either
side, which also provides a safety zone for personnel. The fender system
provides further guidance or a buffer system for the landing craft as it
maintains its position in the water next to the TP to allow the transfer of
personnel.
5.9.7
To ensure the safety of personnel climbing up the ladder a fixed inertia reel
safety system is used. Personnel attach themselves to the fixed safety
system which allows them to climb the ladder freely, however in the event of
a fall or slip it locks in place.
5.9.8
The initial ladder will be approximately 11m long and would extend below
LAT to ensure access at all tidal states. A rest platform is located between
the two ladders. The second ladder would be approximately 5m long.
5.9.9
If space-frame structures are selected the upper ladder may be replaced by
a stairway. This would also be the case if GBS foundations are selected
without a TP.
Access platform
5.9.10
All structures will require access platforms of a minimum 1m width. The
access platform will also include an integral laydown area adjacent to the
access door.
5.9.11
A small davit crane capable of lifting up to approximately 250kg may be
mounted on the main platform, beside the lay-down location. This will be
used to lift the necessary equipment from the boat onto the platform, or vice
versa. Additionally some WTGs may have cameras located on the main
platforms to allow remote observation to take place. These will allow an
onshore based O&M team to assess the sea state and weather conditions at
the WTG, whilst also maintaining visual contact with maintenance operations
in the field.
5.9.12
During the WTG installation phase there is the potential for temporary
generators to be positioned on the main platforms, as the installation
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process will require electricity which might not be available from the shore.
Any fuel for this purpose will be stored in bunded areas.
5.10
WTG Foundation Systems
5.10.1
There are four fundamental foundation options included for supporting the
WTG structures; monopiles, space-frame structures (also known in the
industry as jackets or tripods), gravity base structures (GBS) and suction
monopods. The requirement to permit four foundation types is principally
driven by the large variation in water depths across the site, differing
geological conditions, the potential for use of different turbine types, relative
material and fabrication costs at time of tender and the continuing evolution
of technology in the offshore wind sector.
5.10.2
Given the varying site conditions it is possible that multiple foundation
solutions could be utilised across different areas of each array.
5.10.3
Determination on the final foundation type(s) to be used for the project will be
made following post-consent FEED work.
In the FEED process
consideration will be given to:

Geological profile of the seabed;

Water depth;

Geotechnical properties of soil;

Site metocean conditions (wind, wave, current and tidal regime);

WTG selection;

Access and maintenance requirements;

Foundation material, fabrication, transportation and installation costs;
and

Availability of foundation supply chain components (apparatus / lifting
vessels etc).
5.10.4
The following sections provide an overview of the different foundation
options under consideration together with the typical installation process.
Furthermore, for each foundation type, discussion is provided on the
situations in which each option might be deployed to enable a realistic worst
case scenario to be developed for the EIA (see Chapter 4 EIA Process).
5.10.5
The table below identifies the key controls imposed by the draft DCO and
deemed Marine Licence with respect to this section on ‘foundation systems’.
The table also identifies what flexibility is therefore permitted within each
constraint.
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Table DCO.2
Section: Foundation types
Ref
DCO constraint wording
Sch1,
Pt 1,
1(a)
Comment
Wind turbine generators
Use of any mix of
In practice, no more than
each fixed to the seabed
foundation types in any
one or two foundation types
by one of four foundation
array area. Particular types
are likely to be used for
types (namely, monopile
may be dispersed
commercial reasons and for
foundation, space frame
throughout or concentrated
consistency.
foundation, suction
within specific areas
monopod foundation or
gravity base foundation)
Ability to use different sizes
The ‘worst case’ is defined
and detailed design of
by additional DCO
foundation within the four
constraints for each defined
defined types
foundation type, listed later
in this Chapter.
Monopile foundations
General overview
5.10.6
Monopile foundation systems have been the mainstay of the UK offshore
wind industry to date and are the foundation solution that has been adopted
for the adjacent GGOWF project.
5.10.7
Monopile foundations (Plate 5.5) comprise a single, large diameter hollow
steel pile that relies on the soil to provide lateral resistance to loading. A
separate TP is installed on top of the monopile to provide a horizontal
levelled platform for the WTG structure support. The TP is lifted onto the
monopile and a grout injected into the interface to bond the TP to the
monopile structure. The monopile may also connect to the transition piece
by a welded or flanged connection.
5.10.8
The size (diameter and length) of the monopile depends upon the water
depth, metocean conditions and ground conditions as well as the size of
WTG that it supports. Based on the current knowledge of physical
conditions at the GWF site and experience from the adjacent GGOWF
project, GWFL consider that the WTG options under consideration will
require a maximum monopile size of 7m in diameter and 90m in length.
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Plate 5.5 Indicative monopile foundation
Work
platform
Turbine tower
Intermediate
platform
Boat landing
/ ladder
External
J tubes
Transition piece
Grouted
connection
Scour protection
(if required)
Monopile
Installation process
5.10.9
Installation of monopiles will be carried out using a dedicated heavy lift
vessel (HLV) or a jack-up barge.
5.10.10 A crane will be used on the installation vessel / jack-up barge to manoeuvre
the monopile into a guide frame that supports the monopile during the
installation process (see Plate 5.6).
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Plate 5.6 Monopile installation
Source: GGOWL, 2011
5.10.11 There are two methods of installation for monopiles that are considered to
be applicable for GWF:
 Driven to full penetration; and
 Drive / drill / drive.
Driven to full penetration
5.10.12 The driven method initially allows the pile to sink under its own weight,
following which the required penetration depth (up to 50m below seabed) is
achieved using a hydraulic hammer installed on top of the monopile, as
depicted in Plate 5.7.
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Plate 5.7 Monopile driven installation
Source: GGOWL 2011
Drive / drill / drive
5.10.13 In this method the monopile is again sunk under its own weight and driven
into the seabed using a hydraulic hammer. However, at a pre-determined
refusal point (the ‘first refusal’ gauged by the blow count and travel of the
pile), the pile hammer is removed and a drilling rig system installed within
the monopile.
5.10.14 Drilling takes place to a point typically 0.5m above the final design elevation
of the toe of the monopile. The drilling rig is then removed and the pile
hammer placed on the monopile once again. The monopile is then driven
into the drilled cavity until the required penetration (up to 50m below seabed)
is obtained.
5.10.15 The cutting action of the drill will create spoil or ‘arisings’. These arisings will
be lifted from inside the monopile by using a suction pump unit. The arisings
will be deposited on the seabed in the immediate vicinity of the monopile
base.
Deployment philosophy
5.10.16 As detailed in Table 5.2, GWFL’s assumption based on site conditions and
previous experience is that GWF is likely to deploy monopiles in water
depths up to 45mb LAT.
5.10.17 Up to two piling vessels and rigs may be present and operational at the site
at any one time.
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Table DCO.3
Section: Monopile foundation
Ref
Sch1,
Pt 3,
7(1)
Each monopile foundation
forming part of the
Monopiles could be utilised
at all diameters below 7m.
authorised development
shall not have a diameter
greater than 7 metres
Monopiles of varying
diameter could be used
within the development
Any mix of monopile sizes
could be used within all
array areas
Monopiles of any length or
embedment below the
seabed could be used
Sch1,
Pt 3,
7(2)
Each monopile foundation
forming part of the
Comment
In reality the minimum
monopile size required to
support a 107m diameter
turbine is approximately
5.5m and hence diameters
below this are unlikely to be
used
The use of a regular size
throughout the
development is relatively
likely for commercial
reasons, potentially only
changing where depths are
greater or to support
different turbines
The use of a regular size
throughout the
development is relatively
likely for commercial
reasons, potentially only
changing where depths are
greater or to support
different turbines
Monopiles up to 90m in
length would be utilised.
However key impacts are
governed by the number of
blows to drive the
monopile. Pile embedment
is a function of the strength
of the resisting ground,
hence longer piles will not
result in a greater number
of blows.
Monopiles may be used
anywhere where the depth
from LAT is less than 45m
shall not be constructed in
water with a depth greater
than 45 metres between
LAT and the seabed.
Ref
Sch 6,
Pt 2,
Constraint to be applied by deemed Marine Licence
Number of piling operations and location at any one time
Final Report
Comment
9(c) of the Marine Licence
requires a construction
9V3083/R01/303424/Exet
Chapter 5 - Page 38
9(c)
Sch 6,
Pt 2,
12
Timing of piling operations
Ref
The ‘Habitats Regulations’
& the ‘Offshore Marine
Regulations”
Final Report
Constraint to be applied by other
regimes
Number of piling operations and
location at any one time
method statement to be
approved by the MMO
before licensed activities
commence
12(1) and (2) of the Marine
Licence impose a seasonal
restriction unless otherwise
agreed
Comment
Controlled through an EPS
License application to the
MMO
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Gravity base structure foundations
General overview
5.10.18 Gravity Base Structure (GBS) foundations are typically constructed in steel
or concrete and use their weight to remain stable on the seabed. The GBS
foundation holds position on the seabed through frictional forces, which is
often enhanced by the provision of grout under the base of the structure and
skirts around the structure’s perimeter. These skirts (see Plates 5.8 and
5.8) move the friction plane downwards from the relatively weak surficial
sediments into a stronger undisturbed soil layer below. The skirts also serve
to ensure that any scour that may occur around the perimeter does not
undermine the structure.
5.10.19 GBS foundations will be either conical or column based in shape, as
depicted in Plates 5.8 and 5.9. Maximum dimensions for these structures
are provided in Table 5.2.
5.10.20 GBS foundations are used extensively in other European offshore windfarms
(such as Vindeby, Middelgrunden and Nysted in Denmark).
GBS
foundations have a transition structure (see Section 5.8), which will most
likely be an integrated part of the foundation and upon which the tower will
be mounted.
Plate 5.8 Indicative conical GBS foundation
Turbine Tower
Work Platform
Intermediate Platform
Shaft
Boat Landing / Ladder
Under-base Grout
Internal J-tube &
Ballast
Scour Protection
Skirt
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Plate 5.9 Indicative column GBS foundation
Turbine
Tower
Work
Platform
Intermediate
Platform
Boat Landing
Shaft
External J-tubes
Scour protection
Skirt
Under-base
grout
5.10.21 GBS foundations may require a degree of seabed preparation prior to their
installation to ensure that they are laid on a surface capable of supporting
the structure adequately. This will be confirmed during detailed design postconsent.
5.10.22 Should it be required, seabed preparation is likely to be achieved by means
of mechanical levelling. Inert levelling material (comprising stone or
aggregate) would then be deposited prior to installation of the foundation (up
to 2m depth and approximately 3,000m3 per foundation).
5.10.23 Spoil produced from the mechanical levelling process is likely to comprise
deposits of sand and gravel with limited potential for London clay (where this
is present close to the surface). Spoil will be left in-situ, if permitted, or
removed to a licensed disposal site. GWFL intend to apply for a 'dredging
licence’ if and when required, should this foundation option be taken forward
and as determined by detailed design.
5.10.24 Grout is used to help bond the foundation base to the seabed and is usually
delivered to the GBS by flexible hoses. The maximum volume of grout used
in this process will be in the region of 318m3 per foundation.
5.10.25 The GBS foundations can either be transported to site on a dedicated barge
or as a self floating tow.
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5.10.26 Installation will typically be undertaken through the use of a heavy lift vessel
(HLV) where the gravity base is lowered onto the prepared seabed, or if
floated to site under their own buoyancy, the foundation is ballasted onto the
seabed using tug-boats to control operations. Material used to ballast the
foundation typically comprises rock, gravel, shingle or sand, depending on
the weight required. The source of the ballast material will be confirmed
once the exact type of material to be used has been selected.
5.10.27 Following deployment of the GBS, a fall pipe or similar vessel will install
scour protection material (maximum 3,500m3 per foundation) about the base
of the foundation to prevent seabed scour.
5.10.28 As detailed in Table 5.2, GBS can be deployed in any water depth across
the site where ground conditions are suitable, although they are more likely
to be deployed in water depths up to 45mb LAT.
Plate 5.10 Indicative GBS installation process
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Table DCO.4
Section: Gravity base foundation
Ref
Sch1,
Pt 3,
7(3)(a)
Each gravity base
foundation forming part of
the authorised
development shall not
have:
Gravity bases could be
used at any seabed
diameter below 45m
a diameter at the level of
the seabed which is
Sch1,
Pt 3,
7(3)(b)
Each gravity base
the authorised
have:
Each gravity base
the authorised
have:
The base height is a
function of the excavation
required to create a level
landing area and the
structural depth of the base
itself. There is the potential
for bases to both protrude
and be recessed once laid
relative to existing seabed
level.
Any column diameter below
10m could be utilised.
In reality, there is a
minimum structural limit to
the diameter of the column
capable of supporting a
107m diameter turbine, this
being approximately 6m
and hence diameters below
this are very unlikely to be
used. Furthermore column
diameters are likely to be
consistent above any cone.
If a cone is utilised, it could
meet the main column at
any height at or below 20m
above the base
The maximum cone/column
intersect could be at 27.5m
above seabed level;
comprising a base up to
7.5m above seabed level
and 20m above this
a column diameter, where
there is a flat or conical
base, of greater than 10
metres
Sch1,
Pt 3,
7(3)(d)
Each gravity base
the authorised
have:
a cone/column intersect
which is higher than 20
metres above the top of
the base
Final Report
In reality the minimum
gravity base seabed
diameter required to
support a 107m diameter
turbine is approximately
20m and hence diameters
below this are unlikely to be
used
Any base height below
7.5m would be permitted.
a base height, where
there is a flat base, which
is greater than 7.5 metres
above the level of the
seabed
Sch1,
Pt 3,
7(3)(c)
Comment
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Sch1,
Pt 3,
7(3)(e)
Sch1,
Pt 3,
7(4)
Ref
Sch 6,
Pt 2,
9 (b)
Each gravity base
the authorised
have:
Any form of regular cone
could be implemented to
support the main column,
with any combination of
height and base width
within the constraints set by
(d) and (e)
a cone diameter at its
base which is greater than
35 metres
In the event that any WTG Any mix of base sizes may
uses a gravity base
be used up to 140 number
foundation of more than
WTG, except where there
35 metres diameter at the is a base above 35m
level of the seabed, the
diameter, in which case
only 101 WTG bases may
shall not comprise more
be used
than 101 WTG in total
Exact detailed design of foundations and locations
In reality, base sizes are
likely to be consistent
across large areas of the
site
Comment
9(b) of the Marine Licence
requires submission of a
scheme setting out details
including the number,
dimensions and type of all
foundations
Space-frame foundations
General overview
5.10.29 Space-frame foundations encompass structures that are commonly lattice
type or consist of main legs and braces, typically with three of four legs when
supporting turbines. The most common space-frame structure has been
widely deployed to successfully support offshore oil and gas platforms.
Tripods are a monopile/jacket hybrid in which a large central column is
supported at its base by a frame supported at its three corners. Due to its
braced arrangement and similarities in impacts, tripods are grouped within
the category of ‘space-frame’ throughout this application.
5.10.30 Space-frame systems are typically used to support WTGs in deeper water or
to support heavier WTG, however they may be used at any depth on GWF
or with any turbine type. Space-frames are generally stiffer than a monopile
and more transparent to wave loading. Space-frames are sometimes
installed without scour protection given the small area of contact with the
seabed, relative to monopiles, and low influence on tidal and wave induced
currents.
5.10.31 A space-frame consists of a steel frame with slender leg members with steel
cross bracings throughout their height or acting at a lower level only to
support a central column (tripod arrangement). There are typically three or
four legs, but up to six have been allowed for if used in support of platforms
(see Section 5.11). The members are steel tubes with bracings and are preGalloper Wind Farm ES
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fabricated onshore. The space-frame can be attached to the seabed by long
cylindrical piles (‘pin piles’) up to 125m in length and to a penetration depth
of up to 70m. Plate 5.11 shows a four leg post-piled space-frame structure.
Alternatively suction cans may be used under the leg of each support
structure, resisting force by friction and active suction by seabed penetration
of circa 12m. These are normally made of steel, are cylindrical, have a
closed top and on GWF will be up to 11.5m in diameter for WTG (restricted
to 10m for more than three-legged structures) and up to 17m on offshore
platforms (restricted to 10m for more than 4 legs). Plate 5.12 shows an
indicative suction can substructure.
5.10.32 The TP for space-frame foundations will be an integrated component of the
foundation as described under GBS.
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Plate 5.11 Indicative four-legged space-frame lattice substructure
Pile
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Plate 5.12 Indicative suction can support to a three legged space-frame substructure
Suction can
5.10.33 Installation is usually carried out using a dedicated HLV or a jack-up barge
(as detailed for monopiles). However, as this option is very much in the
development phase in the offshore wind industry, it is possible that a
combination of vessels would be used.
5.10.34 The overall installation process for this system is expected to take up to four
to seven days dependent on the number of legs associated with each spaceframe foundation.
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Plate 5.13
Installation of a three-legged space-frame structure using a heavy lift
vessel
5.10.35 There are two options for the installation of cylindrical pin piles for a spaceframe structure. The pins are significantly smaller diameter (up to 3m) than
those used for the monopile concept (Table 5.2). For pre-piled space-frame
solutions, pin piles may be installed prior to the space-frame, with the
foundation then lowered onto the piles with the legs being inserted into the
piles. Alternatively, the foundation can be placed onto the seabed and the
piles driven through sleeves connected to the space-frame legs.
5.10.36 Should suction cans be used instead of pin piles, installation will be carried
out using a jack-up barge or similar, that lifts and places them onto the
seabed. Pumps will be connected to the suction cans and operated until the
can ‘lid’ is flush with the seabed. In both designs, attachment to the
foundation structure is by a grouted connection.
5.10.37 As detailed in Table 5.2, space-frame systems can be deployed in any water
depth across the site where ground conditions are suitable.
5.10.38 The maximum number of piles installed with a space-frame foundation
system at any one time will be two.
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Table DCO.5
Section: Space-frame foundation
Ref
Sch1,
Pt 3,
7(5)(a)
Comment
Each space frame
All leg spacings below 40m
In reality the reduction in
at the seabed and 25m at
spacing will reach a
the authorised
LAT are permitted
practical minima where the
foundation can no longer
have:
resist the overturning
moment from the turbine
for use with any WTG or
meteorology mast, a
spacing between each leg
at the level of the seabed
which is greater than 40
metres and at the level of
LAT which is greater than
25 metres
Sch1,
Pt 3,
7(5)(b)
Each space frame
All leg spacings below 40m
In reality the reduction in
at the seabed and 25m at
spacing will reach a
the authorised
LAT are permitted
practical minima where the
foundation can no longer
have:
resist the loads from
structure above
for use with any offshore
substation platform,
accommodation platform
or collection platform, a
spacing between each leg
at the level of the seabed
metres in one direction
and 40 metres in a
perpendicular direction,
and at the level of LAT
metres in one direction
and 30 metres in a
perpendicular direction
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Sch1,
Pt 3,
7(5)(c)
Each space frame
In combination with (i),
permits up to 8 piles/4
the authorised
suction cans per WTG
foundation, and 12 piles/6
have:
suction cans per offshore
more than two piles per
platform
leg or more than one
suction can per leg
Sch1,
Pt 3,
7(5)(d)
Each space frame
Individual piles can be any
Whilst possible to change
size at or below 3m
pile sizes on an individual
the authorised
diameter with any mix of
foundation, piles to date
pile sizes on a single
have ordinarily been utilised
have:
foundation and pile designs
in a uniform manner for
are not uniform across the
offshore wind farm
site
foundations, both
a pile diameter which is
more than 3 metres each
individually and across
arrays
Sch1,
Pt 3,
7(5)(e)
Each space frame
Permits any diameter up to
11.5 metres when there are
the authorised
3 or less suction cans for a
WTG or met mast
have:
structure.
meteorology mast, a
suction can diameter
greater than 11.5m each,
where the total number of
suction cans per structure
is 3 or less
Sch1,
Pt 3,
7(5)(f)
Each space frame
Permits any diameter up to
10 metres when there are
the authorised
up to 4 suction cans for a
WTG structure or met mast
have:
(in combination with (i)).
meteorology mast, a
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suction can diameter of
greater than 10m each,
suction cans is more than
3
Sch1,
Pt 3,
7(5)(g)
Each space frame
Permits any diameter of up
to 17 metres when there
the authorised
are 4 or less suction cans
for an offshore platform.
have:
suction can of greater
than 17 metres each,
suction cans is 4 or less
Sch1,
Pt 3,
7(5)(h)
Each space frame
Permits any diameter of up
to 10 metres when there
the authorised
are more than 4 suction
cans for an offshore
have:
platform.
suction can or greater
than 10 metres each,
suction cans is more than
4
Sch1,
Pt 3,
7(5)(i)
Each space frame
(i) permits any number of
All space-frame foundations
legs at or below 4 for a
used in the industry to date
the authorised
WTG or met mast structure
have been 4 or 3 legged. 2
or 6 for a platform.
legs do not provide
have:
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Chapter 5 - Page 51
legs are only likely on larger
more than 4 legs for a
offshore platforms.
WTG or meteorology
mast, or more than 6 legs
for an offshore substation
platform, accommodation
platform or collection
platform
Ref
Comment
Sch 6,
Pt 2,
9(b)
foundations
Sch 6,
Pt 2,
12
Timing of piling operations
Ref
Constraint to be applied by other
12(1) and (2) of the Marine
Licence impose a seasonal
restriction unless otherwise
agreed
Comment
regimes
The ‘Habitats Regulations’
Number of piling operations and
Controlled through an EPS
& the ‘Offshore Marine
location at any one time
License application to the
Regulations”
MMO
Suction Monopod foundations
General overview
5.10.39 Suction monopods are tubular steel foundations that utilise hydrostatic
pressure difference and their deadweight to enable the monopod to
penetrate the soil (up to 20m below seabed). This installation procedure
allows the monopods to be connected to the rest of the structure before
installation, enabling a reduction in the number of steps to the installation
procedure. The system has been tried in practice in the Norwegian oil and
gas fields in the North Sea (DOWEC, 2003) as well as at Horns Rev 2
offshore wind farm for the met mast foundation (see Plate 5.14).
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Plate 5.14 Typical suction monopod foundation
Source: DONGenergy (2009)
5.10.40 Suction monopods may be floated to site under their own buoyancy using
tug-boats or transported on a dedicated barge. Installation is carried out
using a dedicated HLV or a jack-up barge that lifts the monopod into an
upright position and positions it onto the sea-bed. Pumps will be connected
to the suction caisson, following which the ‘monopod’ penetrates into the
seabed until the top surface of the base is flush with the seabed. Small
volumes of seabed sediment may be extracted and deposited locally during
this process.
5.10.41 Suction monopod foundations can be can be deployed in any water depth
across the site where ground conditions are suitable.
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Table DCO.6
Section: Suction monopod foundation
Ref
DCO constraint wording Key flexibility arising
Sch1,
Pt 3,
7(6)(a)
Each suction monopod
All base diameters at or
below 25m are permitted
the authorised
have:
Comment
Any mix of base diameters
is permitted within the
development
a diameter at the level of
the seabed which is
Sch1,
Pt 3,
7(6)(b)
Any height below 7.5m
above the seabed is
the authorised
permitted
have:
a base height, where
Any mix of heights above
seabed level is permitted
there is a flat base, which
is greater than 7.5 metres
above the level of the
seabed
Sch1,
Pt 3,
7(6)(c)
Any column diameter at or
In reality, a column
below 9m is permitted
diameter less than 5m is
the authorised
unlikely due to the
structural support required
have:
to the turbine above
a column diameter which
Any mix of column
is greater than 9 metres
diameters is permitted
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Sch 6,
Pt 2,
9(b)
Comment
foundations
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WTG foundation detail summary
Table 5.2 WTG foundation parameters summary
Foundation detail
Monopiles
Gravity base
systems
Spaceframes
Suction
monopods
Likely maximum water depth
45m
N/A
N/A
N/A
7m
45m
3m per pin
25m
pile or 11.5m
Maximum diameter at seabed
per suction
can
Maximum number of
140
turbines**
Maximum column diameter
140(≤35m Ø)
140
140
101(>35m Ø)
7m
10m
N/A
9m
1
None
8 (2 piles per
None
Maximum number of piles per
leg, up to 4
WTG foundation
legs)
Maximum seabed footprint
38.5m2
1,590m2
85m2 (piled)
(per foundation, excluding
or 314m2
scour)
(suction cans)
Maximum number of ‘legs’
Maximum penetration depth
1
1
4
1
50m
5m
70m (piled) or
20m
12m (suction
below existing seabed level
Maximum volume of grout (per
491m2
cans)
23m3
318m3
212m3
N/A
1,600m3
4,800m3
1,300m3
500m3
foundation)
Maximum volume of arisings
(per foundation)
** GBS may be either up to 45m base diameter, depending on the size of turbine supported.
If a base up to 35m diameter is used, there could be a total of up to 140 turbines. However,
calculations are based on a maximum of 101 of the larger 45m GBS as this option
represents the largest total seabed footprint and which defines the worst case for all gravity
base systems. Between 35m and 45m base diameter, only 101 turbines will be permitted.
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Fabrication and transportation
At the time of writing, the number of foundation fabrication plants and skilled
labour force, whilst emerging, are still limited within the UK. Therefore
foundation structures may be brought in from overseas either directly to site
or to a UK holding port.
5.10.42 If the foundations are shipped to a holding port, there are two principal
methods for transporting the foundations to their installation location:
 Floating transportation procedure; or
 Direct lift procedure.
5.10.43 Floating transportation procedure requires sealing the toe of the pile and
fitting a sealed lifting head at the top of the pile. The sealed lifting head
serves as the towing point. The foundation system is then towed to site after
being lifted into the water using a crane from the holding port key side.
5.10.44 The foundation system is then upended, using a combination of controlled
ballasting and lifting to ensure stability and positioned in a guiding or gripper
system. These systems are used to guide the foundation system to the predefined location on the seabed whilst maintaining verticality.
5.10.45 The alternative transportation method is a direct lift, where the foundations
are lifted from the quayside onto either a dedicated transportation vessel or
the installation vessel itself, which are then used to transport the foundations
to the offshore location.
The foundations are then lifted from the
transportation vessel by a crane on the installation vessel and pitched into
the installation guiding system.
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WTG foundation scour protection
5.10.46 Scouring of soft surficial sediments may occur around foundation structures
where localised effects on the hydrodynamic regime take place (see
Chapter 9). Such scouring erodes sediment leaving depressions (known as
scour holes or scour tails) around the foundation structures.
5.10.47 Experience from the adjacent GGOWF project, where similar seabed
sediments and hydrodynamic conditions exist, would suggest that scour
events sufficient to require dedicated protection are unlikely to be
widespread (only 5 out of 140, or 3.5% of monopile foundations at GGOWF
have scour protection installed to date). For the purposes of the GWF
project a conservative approach has been applied to the likely percentages
of foundations that may require scour protection, meaning the estimates
given are the ‘worst case’ for what might be required (see Table 5.3).
Table 5.3 WTG foundation scour detail summary
Foundation detail
Monopiles
Gravity base
systems
Spaceframes
Suction
monopods
7m
45m
3m per pin
25m
Maximum diameter of
pile or 11.5m
foundation at seabed
per suction
can
Maximum scour protection
20m
10m
5m (piled) or
(radius beyond the
6m (suction
outermost perimeter of each
cans)
10m
foundation/leg base)
1,700m2
1,730m2
1,510m2
area (per foundation,
(piled) or 962
comprising all legs where
m2 (suction
relevant)
cans)
1,100m2
2m
2m
2m
2m
3,400m3
3,460m3
*3,020m3
2,200m3
depth (per foundation)
(piled) or
1,924m3
volume (per foundation)
(suction
cans)
Approximate percentage of
10%
100%
foundations requiring scour
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25% (piled)
100%
or 100%
9V3083/R01/303424/Exet
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Foundation detail
Monopiles
Gravity base
systems
protection
Spaceframes
(suction
Suction
monopods
cans)
Volume of scour protection
34,300m3
Not required
Not required
extra
for cable entry (for
required for
maximum 140 turbines)
35,600m3 (no
suction cans)
82,000m3
349,500m3
volume (cable entry and
(for worst
foundations for 140 turbines,
case 101 x
except GBS at 101 no.)
45m base)
141,300m3
308,000m3
(piled) or
269,360m3
(suction
cans)
* Assumes 2 piles and one support at each leg, therefore comprising 3 no. 3m
obstructions. The area assumes that there is no overlap between the area of scour
protection around each obstruction, whereas in reality this would occur, thus reducing
the overall volume per foundation.
5.10.48 A pre-construction geophysical survey (see Section 5.5) will help to
ascertain the level of scour protection required for the proposed GWF
project. Surveying for any scour will continue beyond the construction phase
of the project and will form part of the ongoing inspection regime of the wind
farm.
5.10.49 Should scour protection be deemed necessary, the following is a typical
installation procedure:
 A filter layer of gravel is installed prior to placement of the foundation;
 Rock or slate is deposited at the base of the foundation structures
after installation of the foundation. The rock placement would infill
any scour pit, which may have developed, as well as building a profile
above the seabed, referred to as a rock berm. The rock berm will be
designed to remain stable for the full life of the structure under all
forms of predicted environmental loading;
 The rock or slate is placed by a vessel using a side tipping system,
deposited by a fall pipe vessel or placed using a grab device; and
 The base of the structure will be resurveyed to confirm that the
required coverage and rock profile has been achieved.
5.10.50 There are other scour protection solutions that are being tested for use in the
industry that may also be considered for use. These include concrete
mattresses, rock filed gabian bags and frond mats.
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Foundation installation noise (all foundations)
5.10.51 All marine construction activity generates some level of noise. The
installation of the foundation systems, however, has the potential to generate
significant noise levels. Underwater noise behaves very differently to
airborne noise largely due to the high sound transmission speed within water
(1,500m/s, as opposed to 340m/s for air). The effects of this noise on the
sensitive ecological receptors (namely ornithology, fish and shellfish and
marine mammals) are discussed in Chapters 11, 13 and 14 respectively.
5.10.52 The two foundation systems which can be expected to result in the highest
noise levels are those that have impact piling associated with their
installation, namely monopiles and space-frame foundation structures (that
use pin piles).
5.10.53 Impact piling involves a large weight or “ram” being dropped or driven onto
the top of the pile, driving it into the ground. Usually double-acting hammers
are used in which compressed air not only lifts the ram, but also imparts a
downward force on the ram, exerting a larger force than would be the case if
it were dropped under the action of gravity.
5.10.54 Airborne noise is created by the hammer, partly as a direct result of the
impact of the hammer with the pile. Some of this airborne noise would be
transmitted into the water. Of more significance to underwater noise,
however, is the direct radiation of noise from the surface of the pile into the
water as a consequence of the compressional, flexural or other complex
structural waves that travel down the pile following the impact of the hammer
(Chapters 13 & 14; Subacoustech, 2011). Due to the high transmission
properties of sound in water (1,500m/s, as opposed to 340m/s for air), noise
generated from pile installation will transmit efficiently into the surrounding
water column. Consequently these waterborne sound waves usually provide
the greatest contribution to underwater noise (Subacoustech, 2011).
5.10.55 At the end of the pile, force is exerted on the substrate not only by the mean
force transmitted from the hammer by the pile, but also by the structural
waves travelling down the pile inducing lateral waves in the seabed. These
may travel as both compressional waves, in a similar manner to sound in the
water, or as a seismic wave, where the displacement travels as Rayleigh
waves (Brekhovskikh, 1960). The waves can travel outwards through the
seabed, or by reflection from deeper sediments. As they propagate, sound
will tend to travel upwards into the water, contributing to the waterborne
wave. Since the speed of sound is generally greater in consolidated
sediments than in water, these waves usually arrive first as a precursor to
the waterborne wave. Generally, the level of the seismic wave is 10 to 20
decibels (dB) below the waterborne arrival, and hence it would be the latter
that dominates the noise impact.
5.10.56 Studies carried out to date (Nedwell et al., 2003; Nedwell et al., 2007; Parvin
et al., 2006) indicate that the source level of the noise from impact pile
driving operations is primarily and strongly related to the pile diameter. This
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probably results largely from the increased force that is required to drive
larger piles and the improved noise radiation efficiency of larger piles
(Subacoustech, 2011).
5.10.57 For GWF the maximum sized piles proposed are 7m in diameter (for
monopiles) and 3m diameter for space-frame foundations using pin piles.
There is currently no measured data for piles of 7m diameter, but using
extrapolation from other pile diameters, it is possible to establish indicative
noise levels from GWF piling operations (Subacoustech, 2011).
5.10.58 In instances where a single defined noise is emitted underwater, sound
pressure measurements may be expressed using a ‘peak to peak’ level (i.e.
dB re 1μPa @ 1m), which represents the noise level at a distance of one
metre from the source. The actual level at the source (Source Level) may
be different from that experienced at one metre. The Source Level for a
piling source this is typically expressed as having a “peak to peak Source
Level of dB re 1μPa @ 1m”.
5.10.59 Based on this approach it is predicted that noise levels of 254dB re 1 µPa @
1m for 7m diameter piles and 239dB re 1μPa @ 1m for the 3.0m diameter
piles may be expected for the GWF project (see Plot 5.2). It should be
noted that Source Levels calculated from measurements undertaken by
Subacoustech Environmental have been used to help determine the fit line
used to derive the Source Levels used for this study. These are not included
here due to Subacoustech Environmental not having permission to release
other clients’ data for this report. Further details are available in
Subacoustech, 2011.
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Plot 5.2 Predicted noise levels from GWF piling operations (Subacoustech, 2011)
5.10.60 The implications of the noise generated from construction activity on the
receiving environment are assessed and discussed within the relevant
technical chapters of this report (namely Chapter 13 Fish and Shellfish
Resource and Chapter 14 Marine Mammals).
Foundation corrosion protection (all foundations)
5.10.61 Any offshore metal structure (typically steel) in contact with sea water will
corrode freely without corrosion protection. Corrosion can reduce the
structural integrity of support structures, hence corrosion protection is
required. The design of the internal and external corrosion protection
systems (CPS) utilised at GWF will be subsequently agreed with the
Certification Bodies, namely Det Norske Veritas (DNV), Germanischer Lloyd
(GL) or Lloyds Register, who will be responsible for certifying the subsea
structure.
Internal corrosion protection
5.10.62 Internal corrosion prevention measures are required in subsea foundation
types comprised of steel (i.e. all excluding concrete GBS foundations) as a
result of the sea water that is trapped inside the structures after installation.
Corrosion in this instance is predominately caused by microbial activity, both
aerobic (with oxygen) and anaerobic (without oxygen) in nature. Sealing the
tops of the foundation structures and removing the oxygen (by filling the
space with an inert gas) will be the primary method to limit the growth of
microbes.
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5.10.63 If through investigation the rate of microbial corrosion is deemed to be high,
then additional measures could be undertaken after sampling the sea water
captured in the foundation during the installation process. A biocide could
be used to inhibit the growth of the microbes responsible for corrosion,
although foundations would not be designed to rely on their use. However in
time internal investigations and water sampling could identify the need for
their use. Biocides are used extensively in the offshore industry to control
internal corrosion. If biocides are used the necessary licences will be sought
with risk assessments and method statements put in place.
External corrosion protection
5.10.64 The external corrosion protection system (CPS) selected for the TP and
foundation will be required to ensure protection against corrosion and to
ensure that the design life of the project is met. The external CPS will
comprise two primary systems; an external coating system and a cathodic
protection system provided by one of the following forms:
 Galvanic CP, commonly referred to as a sacrificial anode; or
 Impressed current cathodic protection (ICCP).
5.10.65 The basic principle behind CPS is electrolysis which requires an anode (a
source of negative ions), a cathode (a source of positive ions) and an
electrolyte (a liquid which will conduct the ions, i.e. the sea). A CPS only
operates on the outermost exposed surfaces of the steel structure at the
molecular / atomic level; simplistically a protective force-field to prevent
corrosion.
5.10.66 The galvanic CP or sacrificial anode system is used heavily in the oil and
gas offshore industry. This system, as the name suggests, uses fixed
anodes, usually zinc, magnesium or aluminium (or alloys of these metals)
placed about the base of the submerged structure which remains there for
the life of the equipment. As the anode is more easily corrodible, there is a
continual electron flow from the anode to the cathode (steel structure)
causing polarisation. The driving force for the CP current flow is the
difference in electrochemical potential between the anode and the cathode.
Galvanic corrosion protections are generally specified to provide adequate
protection for the design life of the foundation. Due to the challenging nature
of cathodic protection design, it may be necessary to replace the anodes
within the foundation design life.
5.10.67 The ICCP system is commonly found on boats and submarines. ICCP uses
anodes connected to a directional current (DC) power source; current is
supplied to the anodes causing the cathode (the steel structure) to become
more electronegatively charged and therefore reduces its rate of corrosion.
In this case reference electrodes on the structure are also required to
monitor the electrical potential.
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Table DCO. 7
Other foundation parameters
Constraint to be applied by deemed Marine
Licence
Sch 6,
Extent of scour protection
Pt 2,
9(e)
Comment
A scour protection
management and cable
armouring plan must be
submitted to the MMO for
approval under the marine
licence
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5.11
Ancillary Infrastructure
Offshore substation platform(s)
5.11.1
The principal purpose of an Offshore Substation Platform (OSP) is to house
the transformers required to increase the distribution voltage (typically 66kV
or above) of the inter and intra-array cables to a higher voltage (132kV) for
the export cables.
5.11.2
Between one and three OSPs will be required for the GWF project. The
flexibility in the number of OSPs is reflective of the potential to develop a
range of layouts utilising one, two or three of the three distinct development
Areas, with each area most likely to receive one OSP.
Topsides
5.11.3
The topside is the name for the structure which is placed on top of the
foundation structure and completes the OSP. It may be configured in either
a single or multiple deck arrangement. Decks will either be open with
modular equipment housings or the structure may be fully clad. All weather
sensitive equipment will be placed in environmentally controlled areas.
5.11.4
The offshore substation(s) will be up to 75m high, 65m long and 50m wide.
The maximum height is measured as 30m from LAT to the base of the
topside and a further 45m for the actual height of the structure. Although
considered unlikely, it is possible that some associated masts may exceed a
height of 75m.
5.11.5
The OSP will be fabricated at a quayside facility to enable the transfer of the
topside structure onto a barge for transportation offshore. Whilst at the
quayside the topside will be fitted out internally with all the necessary
equipment. As far as possible the equipment will be made ready for
operation prior to being moved offshore.
Environmental mitigation
measures, such as transformer bunding, will be fully operational prior to the
OSP transportation phase.
5.11.6
The OSP will typically accommodate the following:
 Helicopter landing facilities;
 Refuelling facilities;
 Potable water;
 Black water separation;
 Medium (MV) to high voltage (HV) power transformers;
 MV and/or HV switch gear;
 Instrumentation, metering equipment and control systems;
 Standby generator;
 Auxiliary and uninterruptible power supply systems;
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 Marking and lighting;
 Emergency shelter, including mess facilities;
 Craneage; and
 Control hub.
Discharges
5.11.7
The OSP’s drainage system will collect waste water as well as connecting
bunded areas. The drainage system will incorporate a separation unit which
separates any contamination from the collected water. The collected water
is re-circulated through the separator until the water complies with
requirements, prior to discharge to the sea.
5.11.8
The collected contamination will be drained into a storage facility, for
transportation to shore and controlled processing and/or disposal.
Foundations
5.11.9
The offshore platform(s) foundation will most likely comprise a space-frame
foundation system analogous to that described in Section 5.10 for the WTG
(Table 5.2), only of a larger size and with up to 6 legs. Platform spaceframe structures will be fixed to the seabed either by pin piles or suction
cans. Suction founded space-frames will have a maximum of 4 legs.
Dimensions (including details of scour protection volumes) are given in
Table 5.4. Alternatively the offshore platform(s) may be supported by a
monopile foundation.
5.11.10 The existing GGOWF project uses a square lattice type foundation with
cylindrical piles, driven through sleeves into the seabed at each of four legs.
The advantages of the lattice space-frame are that it provides the most
protective solution for the incoming inter and intra-array and export
submarine cables and also enables the OSP to be deployed in any water
depth within the array.
Table 5.4 Platform foundation summary
Foundation detail
Maximum diameter of foundation at seabed
Spaceframe
(piled)
Spaceframe
(suction
can)
Monopile
3m per pin
17m
7m
pile
Maximum number of ‘legs’
6
4
1
Maximum scour protection (radius beyond the
5m
12m
20m
outermost perimeter of each foundation/leg
base)
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Foundation detail
Maximum scour protection area (per foundation,
Spaceframe
(piled)
Spaceframe
(suction
can)
Monopile
2,262m2
4,373m2
1,700m2
2m
2m
2m
4,524m3
8,746m3
3,400m3
100%
100%
100%
comprising all legs where relevant)
Maximum scour protection depth (per
foundation)
Maximum scour protection volume (per
foundation)
Assumed percentage of foundations requiring
scour protection
Volume of scour protection for cable entry (for
Included below
maximum 140 turbines)
Maximum scour protection volume (up to 4
18,100m3
35,000m3
13,600m3
platforms)
Accommodation platform
5.11.11 An accommodation platform may be required to provide accommodation and
suitable landing points for vessels or helicopters.
5.11.12 The foundation for an accommodation platform will be similar to the OSP (if
space-frame), but likely to be smaller in size. The topside will be large
enough to contain emergency shelter and facilities for crews undertaking the
necessary work offshore. Power and communication links will need to be
installed, with a standby generator in case mains electrical supply is lost.
Fabrication of the space-frame and topside will take place onshore, with
transportation to the offshore location before being lifted into position.
Collection station
5.11.13 Once the location of the turbines has been finalised, an electrical design to
link the turbines together will be undertaken. The electrical design study will
determine if a collection station is needed. Subsequent development of the
initial design proposal will then determine the location, substructure and
dimensions of the necessary collection station.
5.11.14 The role of the collection station is to facilitate the electrical connection of
several turbine electrical strings so that the total generated power from them
can be exported on a single cable.
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5.11.15 The collection station will be housed on a similar substructure to that of the
WTG. The foundation type for the collection stations will be either a
monopile or space-frame. Either of these foundation types could contain a
number of J-tubes.
5.11.16 Transformers, if required, would be located on the collection stations to step
up the voltage, for instance from 33kV to 66kV. This would assist the energy
efficiency of the site as higher transmission voltages incur less electrical
power loss. This must be offset with the fact that transformers themselves
consume electrical energy. Consequently the installation of transformers is
a less attractive option.
5.11.17 The topside of the collection station will comprise electrical switchgear, thus
dimensionally small, and lighter than a complete WTG. If the collection
station is required to house a transformer the floor plate will be larger.
Meteorological mast(s)
5.11.18 Up to three permanent meteorological (met) masts are envisaged for the
GWF project. The met masts will be installed in key locations within the
array Areas.
5.11.19 Met masts are used to verify the MW output of the WTGs, and additionally
provide data for the wind forecasting module to help predict the next day’s
wind pattern. Met masts will be placed on a monopile, space-frame, gravity
base or suction monopod foundation structure. A topside, or deck protected
from the elements will be required, which is large enough to house electrical
switchgear and communication equipment, along with back-up systems.
Ancillary structure summary
5.11.20 Table 5.5 provides a summary of the proposed maximum offshore ancillary
infrastructure.
Table 5.5 Summary of ancillary infrastructure
Detail
Maximum number
OSP / Collection station /
Accommodation platform
Met-mast
4 (up to 3 no. OSP, 1 no.
3
Collection, 1 no.
Accommodation)
Maximum height (above LAT)
Foundation options
75m
120m
Space-frame and monopile
Monopile, GBS, space-
(as detailed in Table 5.2)
frame and suction monopod
(as detailed in Table 5.2)
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Table DCO.8
Section: Other Offshore platform and met mast constraints
Sch1,
The total number of
Any combination of
Pt3,
offshore substation
different platform types is
5(1)
platforms, accommodation
permitted
Sch1,
Pt3,
5(2)
Comment
Scheme is limited to one
by Work No 1(b) of the
platforms and collection
DCO; one collection
platforms forming part of
platform limited by Work
the authorised
No 1(c); no more than
three met masts limited by
exceed four
Work No 1(d).
The dimensions of any
Any clearance to MHWS is
offshore substation
permitted and any size
platform, accommodation
below those stated is
platform or collection
permitted
platform forming part of the
(excluding any masts) shall
not exceed 75 metres in
height when measured
from LAT, 65 metres in
length and 50 metres in
width.
Sch1,
Pt3,
5(2)
Nor shall it [any offshore
Work No 1(b) of the DCO
restricts the
accommodation platform or
accommodation platform to
collection platform forming
a monopile or space-frame
part of the authorised
type foundation only. Work
development] have more
No 1(c) restricts the
than one supporting
collection platform to
foundation
monopile or space-frame
type foundation only. Work
No 2 restricts the offshore
substation platforms to
monopile or space-frame
type foundation only
Sch1,
Pt3,
No meteorological mast
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5(3)
shall exceed a height of
adopt any height below
120 metres, nor shall it
and including 120 metres.
have more than one
supporting foundation
Sch 6,
Pt 2,
9(b)
Any foundation type is
Confirmed by Work 1(d) of
permitted on met masts
the DCO
Comment
foundations
5.12
Inter, Intra-array and Export Cables
Inter and intra-array cables
5.12.1
Inter-array cables will be laid between the different array areas (assuming
more than one Area is developed) and intra-array cables will be laid between
turbines as illustrated in the example Figures 5.3 to 5.5. The total length of
inter and intra-array cables will be up to 300km.
5.12.2
The inter and intra-array cables collect and transfer power generated in the
WTGs to the OSP(s), potentially in different key areas of the project. The
cables connect the WTGs together into strings, with the maximum number of
WTGs connected together depending on WTG size and cable rating. The
strings of turbines would then in turn be connected to the offshore platform,
possibly via a collection station.
5.12.3
The intra-array cables between adjacent WTGs will be relatively short in
length, typically in the range of 650m to 2,000m. However, some intra-array
cables (e.g. those between the last turbine in the string and the OSP) could
be significantly longer and may pass between arrays, i.e. becoming interarray, except at a lower voltage.
5.12.4
The precise inter and intra-array cable layout will be defined following
detailed FEED studies. In addition, the decision as to whether a radial,
looped or branched arrangement is adopted will be made following further
site investigations and will be influenced by a combination of ground
condition and economic factors (as for the WTG layout determination). For
the purposes of informing the reader of this ES, illustrative inter and intraarray cable layouts are provided in Figures 5.3 to 5.5.
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5.12.5
The cable size will be expected to increase from the far end of the strings to
the OSP to accommodate the increasing power that is carried. It is possible
that intra-array cables up to 213mm diameter could be used throughout the
wind farm.
5.12.6
The inter and intra-array cables will typically be rated at 33kV, and will carry
the electrical energy generated by the WTGs to a central location, such as
an OSP or Collector Station. The inter or intra-array cable will be a single
armoured submarine cable, containing 3 electrical conducting cores and an
optical fibre cable. Plate 5.15 shows the typical cross-section of a single
armoured submarine cable.
Plate 5.15 Typical single armoured submarine cable
Source: GGOWL, (2009)
Export cables
5.12.7
Up to three export cables will be required to transfer the wind farm output to
shore. The final number of export cable circuits will depend on the final wind
farm design. It is possible that the export cables will also allow for data to be
transferred using optical fibres.
5.12.8
Export cables will be three phase Alternating Current (AC) cables with a
rating of 132kV. The cable will be extruded cross linked polyethylene
(XLPE) insulated, and wire armoured, for erosion protection.
5.12.9
The export cables comprise the cabling from landfall to the wind farm site
and any inter-connecting cabling between the OSP within the potential
separate array areas (see illustrative examples in Figures 5.3 to 5.5).
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Proposed export cable route
5.12.10 A dedicated geophysical survey has been undertaken on a corridor between
500m and 1,000m wide within which the export cable route will be
established (see Chapter 9). A corridor of this width is required to account
for adequate spacing between the cables (up to three) and any minor
deviation required due to obstacles including aggregate extraction (see
Chapter 18 Human Activity), marine archaeology / wrecks and other
magnetic and sonar contacts (see Chapter 19 Archaeology) and
sandwaves (Chapter 9).
5.12.11 The philosophy behind this route selection is provided in Chapter 6 Site
Selection and Alternatives.
5.12.12 The precise export route within the corridor will be established following
detailed FEED studies and further site investigation post-consent.
Cable manufacture & transportation
5.12.13 The estimated minimum length of each export cable, depending on the final
route, will be approximately 50km. This is estimated from the likely position
of the nearest offshore substation to the landfall at Sizewell. Additional
export cables, up to two circuits (approximately 20km each), would be
expected to connect the first OSP to the most distant OSP, to allow
connection to OSPs that are more distant from shore, potentially being as far
as Area C. Therefore, it is estimated that the total length of subsea export
cable required will be up to 190km. Table 5.6 summarises the key
parameters for the AC export cables.
5.12.14 Plate 5.16, below shows an AC export cable being loaded into a carousel - a
circular rotating cage mounted onto the back of an installation vessel. The
vessel transports the export cable to the required location from where it is
initially pulled into position and then installed slowly into the seabed as
described in the following sections.
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Plate 5.16 Export cable being loaded into a carousel
Cable installation
Pre-installation works
5.12.15 The preferred cable route will be surveyed (via a pre-construction
geophysical survey) to locate any obstacles that may obstruct cable laying
(e.g. rocks, wrecks, metal objects, unexploded ordnance). If an obstruction
is located it will be assessed and an appropriate strategy will be established
to remove or avoid the obstruction. Typically a Pre Lay Grapnel Run
(PLGR) and ROV survey are conducted to clear the obstruction. Where the
obstacle is suspected to be UXO, specialist mitigation will be employed to
either avoid or make the obstruction safe.
5.12.16 The geophysical surveys will also serve to identify the location of sand
waves along the cable route so that an assessment can be made as to
whether such features can be avoided or, if not, what level of seabed
preparation (pre-lay sweeping) is required, and what the appropriate burial
depth will be in stable (i.e. non mobile) seabed conditions.
5.12.17 Prior to cable installation, cable burial trials may be conducted in advance of
the main installation programme to ensure that the chosen equipment will be
suitable for the ground conditions encountered and that an appropriate burial
depth can be achieved. If undertaken, any such trial may involve lengths of
up to 1km in each of the soil types likely to be encountered along the export
cable route.
Cable installation methods
5.12.18 There are several different methods available for the installation of
submarine cables:
 Simultaneous lay and burial using a cable plough;
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 Post lay and burial using a jetting ROV; and
 Simultaneous lay and burial/post lay and burial with a mechanical
trencher.
5.12.19 The final decision on installation method will be made on completion of the
pre-construction geotechnical site investigation surveys. However, it is
noteworthy that the GGOWF project has utilised a combination of ploughing,
jetting and trenching to accommodate the variation in sedimentary conditions
encountered along the cable routes.
Cable burial by ploughing
5.12.20 Cable burial ploughs cut through the seabed, lifting the soil from the trench.
Cable ploughs are designed to cut a narrow trench, with a slot of material
temporarily supported before falling back over the trenched cable.
5.12.21 The advantage of this method is that burial can be achieved as the cable is
laid, thus minimising risk to the cable. However, the number of vessels
which can carry out this method and that have the required cable carrying
capacity for “heavy” power cable is limited.
5.12.22 The performance of a plough and the depth of burial which can be achieved
are a function of plough geometry and seabed conditions, with dense / stiff
soils providing the greatest challenge.
5.12.23 A typical cable burial plough (such as the Sea Stallion 4, as shown in Plate
5.17) excavates to a width sufficient to enable insertion of a cable up to
280mm in diameter. The plough itself is typically around 5m in width,
although the operating footprint on the seabed will be much smaller than
this.
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Plate 5.17 Example cable burial plough
Source: www.VSMC.nl
Cable burial by jetting
5.12.24 Where seabed conditions are predominantly soft sediment material it may be
considered appropriate to bury the array cables with a dynamically
positioned (DP) vessel post installation.
5.12.25 Under this process the cable is laid on the seabed first and a Remote
Operated Vehicle (ROV) fitted with high-pressure water jets positioned
above the cable. The jets fluidise a narrow trench into which the cable sinks
under its own weight. The jetted sediments settle back into the trench and
with typical tidal conditions the trench coverage would be reinstated over
several tidal cycles.
Cable burial by trenching
5.12.26 In locations where seabed conditions comprise very stiff soils (typically over
100kPa) and/or bedrock, ploughing and jetting techniques may not be
appropriate for cable burial.
5.12.27 One approach for installing cables in very stiff/hard seabeds will be to use
mechanical trenchers which can either be used to simultaneously bury the
cable as it is laid or in a “post lay” mode where the cable is laid by one
vessel and burial is achieved by another vessel spread following on behind.
Simultaneous lay and burial of the cable tends to be preferred since this
reduces risk to the cable from exposure. However, if a post lay burial
solution is used then typically the length of time of exposure will only be a
few hours (depending on the exact arrangements). During this time any
unburied lengths of cable will be protected using a guard vessel.
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5.12.28 It should be noted that simultaneous lay and burial can also be achieved by
ploughing in stiff materials to 140KPa and above (e.g. chalk) by use of
specially designed “rock ripping” ploughs as well as certain types of
“standard” subsea plough. For example, in the recent installation on
GGOWF the export cable was installed through stiff/hard crag material using
a standard “Sea Stallion” subsea plough. Any spoil from trenches (left proud
of the seabed surface) will be left to naturally winnow away by tidal currents,
which typically takes two or three tidal cycles.
Plate 5.18 Example cable burial trencher
Source: Pharos offshore group
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Cable installation procedure
5.12.29 A cable barge or specialist cable installation vessel is likely to be required to
install the cable into the seabed. The array cables will be supplied on cable
reels or loaded onto the vessel in one continuous length. Collection will take
place from the manufacturer’s facilities or holding docks prior to
transportation to the ploughing vessel.
5.12.30 The vessel then travels to site and takes up position adjacent to the start
location (WTG for inter and intra-array cabling or OSP / the shore for export
cabling). The vessel will either hold station via a DP system or set anchors
in a stationary mooring pattern. One end of the array cable will then be
floated from the cable reel towards the substructure / shore. The cable will
then be laid away from the substructure / shore in a direction towards the
landfall / OSP. The cable installation vessel will either move under DP
control or by hauling on its anchors; if the secondary method is used then
redeployment of the anchors will be required.
5.12.31 Depending on the design of the relevant substructure, the cable is sunk and
fed through the J-tube and lifted / pulled into the transition piece, or pulled
through a pre-installed J-tube attached externally to the substructure.
5.12.32 The cable installation vessel’s ability to get close to shore is dependent on
the draft of the vessel in question (but is typically around 10m), at which
point water depths are too shallow to proceed. At this time the installation
vessel will hold its position either by use of a Differential Global Positioning
System (DGPS) or anchors whilst the cable is brought (floated) to shore. If a
cable barge is used then the draft is usually suitably shallow to enable
access to shore. The process of connection to shore is discussed in detail in
Section 5.13.
Cable burial depths
5.12.33 Appropriate cable burial depth will be determined by a detailed hazard
identification survey post-consent, which will assess the different locations
and the various shipping and dredging activities. It is possible that the
hazard identification survey will identify places where the depth may vary
due to local features, such as:
 Sand waves;
 Erosion of the seabed;
 Intense demersal fishing; and
 Existing infrastructure (such as cables) or observed seabed
obstacles.
5.12.34 The representative average burial depth of export, inter and intra-array
cables used in this ES is 1.5m, with the aim of achieving a minimum of 0.6m.
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However, whether or not this is possible will be highly dependent upon the
equipment used, the exact ground conditions experienced during
construction and an assessment of risk to cables.
Cable lay protection
5.12.35 Achieving target burial depths (as determined by the post-consent burial
assessment) for export, inter and intra-array cables will not be possible in
close proximity to the WTG and OSP, where the cables rise up to connect to
the J-tube of these structures. Typically these sections may be in the region
of 20m in length (DOWL, 2009).
5.12.36 There are three surface based protection measures which may be utilised
for cable protection:
 Extension of the scour protection rock placement (if being used) to
cover the final 20m of cable on the seabed;
 Use of concrete mattresses which are lifted and placed over the cable
sections (see cable crossings section for further detail of this
methodology). This methodology is sometimes supplemented with
the use of sandbags to stabilise the edges of the mattresses; and
 Use of grout bags which can be placed over the lengths of cable and
then inflated with structural grout. The grout then cures to provide an
effective cover protection system for the cables. This approach
requires diver assistance.
5.12.37 Alternative protection may also be required where it is impossible to achieve
the target burial depth (e.g. where seabed conditions prevent access for the
installation equipment). Experience from the adjacent GGOWF project
would suggest that the likelihood for significant levels of cable lay protection
under such circumstances would be limited.
Cable separation
5.12.38 Cables must be laid with a separation distance so that, in the event of a
fault, repairs can be carried out without risk of damaging the adjacent
cables.
5.12.39 It is anticipated that a nominal spacing of 60m between cables will be
utilised, which would be sufficient to avoid conflict with anchor spread, whilst
decreasing the risk from damage through cable ploughing activity for
adjacent cables. The cable separation will need to be reduced to a suitable
width (to be determined during detailed design) at the shoreline as the
cables approach the cable ducts at the landfall point.
5.12.40 On the approach to the shore, and to allow the cables to pass south of
Sizewell, the GWF cables will enter the GGOWF export cable corridor (as
defined by The Crown Estate).
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Cable crossings
5.12.41 There are four active telecommunication cables that will require crossing,
three by the export cable route and one within Areas A and B (assuming
areas of A and B are developed that impact on this cable) (see Chapter 18).
Given that there will be up to three export cables, there will be up to 9
crossings required along the export cable corridor. The number of crossings
associated with the intra-array cabling will be determined following design
optimisation and confirmation of final layout post consent.
5.12.42 The International Cable Protection Committee (ICPC) has issued a
recommendation for crossing arrangements between telecommunication
cables and power cables. This recommendation outlines how, and why, a
Crossing Agreement should be put together, but does not describe the
physical construction of a crossing.
5.12.43 There is no single universally accepted crossing design that would be
applicable in all situations. Designs vary with the seabed properties at any
particular location. Each crossing will have a range of features possibly
unique to that location, based on:
 The physical properties of the crossing product, for example the cable
size and weight, bend radius and armouring;
 Protection requirements relative to the hazard profile, including depth
of burial or extent of mattress/rock cover;
 The physical properties and protection status of the crossed product;
 Seabed properties at the crossing point, for example substrate type,
morphology and stability - presence of mobile bedforms; and
 Any constraints placed by the crossed party, for instance location and
burial determination standards, maintenance clearance zone, plough
approach limits and notification zone.
5.12.44 The minimum vertical separation distance between the two cables is likely to
be governed by the requirements of the crossed party and construction
methodology. This is normally 0.3m (from a mechanical separation point of
view).
5.12.45 The components most commonly used to protect telecommunication cables
are flexible mattresses and graded rock. These components may be used
exclusively or in combination.
5.12.46 The telecommunication cables lying on the export cable route will require
multiple crossings (given that there would be three export cables). Crossing
the cables at one point, via a single physical structure, is the preferred
option.
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Mattresses
5.12.47 Mattresses made from elements of concrete or bitumen are widely used to
protect from seabed hazards where burial is not viable or is not effective.
The most common form of mattress is that made of concrete elements
formed on a mesh of polypropylene rope, which can conform to changes in
seabed morphology. Bevelled elements are used on the periphery to create
a lower profile to encourage hazards such as trawl gear to roll over the
mattress. Typically, mattresses of 6m by 3m and 150mm to 300mm in
thickness will be used for cable crossings. Plate 5.19 illustrates an example
of a fully mattressed crossing design.
5.12.48 If sediment dynamics are appropriate, mattresses fitted with polypropylene
‘fronds’ may be used to enhance the protection provided, as the fronds
encourage transient sediments in the water column to be deposited, in the
best case creating a protective sand bank. Where the burial depth of a
cable is zero, shallow or ambiguous mattresses can be configured to reduce
the risk of direct contact.
Plate 5.19 Fully mattressed crossing design
Source: GGOWL, 2009
5.12.49 A site specific geophysical survey will confirm the precise crossing point
(with areas of level seabed and suitable cover over the existing cable being
preferable). Mattresses are then lowered into place from a dedicated vessel,
with divers if necessary to ensure accurate deployment. The export cable(s)
will be laid on the primary layer of mattresses and a second layer of
protective mattresses will subsequently be installed on top of the cable. The
cable burial equipment will then bury the cable into the sediment, and extra
mattressing or rock dump material applied to ensure suitable burial depth is
maintained where the cable re-enters the sediment.
Rock placement
5.12.50 Rock placement has long been established as a method for constructing
crossings. The rock used is normally imported from land quarries, although
sea aggregates can also be used, with the sizes being tailored to achieve
the necessary protection. Rock is usually be deposited by a fall pipe vessel
where the water depth is adequate as this is the most efficient method of
getting the material onto the seabed. In very shallow waters a specialist
vessel fitted out with basic equipment for pouring the aggregate over the
side may be used.
5.12.51 On fall pipe vessels, the aggregate is conveyed to the side of the ship and
freefalls down a chain-mail pipe. At the end of pipe would be an ROV, which
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may be used to adjust the delivery point relative to the ship. The combined
movements of the ship and ROV are used to construct the necessary
bridging and protection berms. The fallpipe ROV would survey the position
and shape of structures created, using acoustic profilers and other devices.
5.12.52 Rock placement is a relatively quick operation and is not as weather
dependent as mattressing.
Cables summary
5.12.53 Table 5.6 provides a summary of the offshore cabling system.
Table 5.6 Summary of cable parameters
Cable detail
Inter and intra-array cables
Export cables
(Offshore)
Maximum voltage
66kV
132kV
Maximum external cable
213mm
258mm
Number of cables
See paragraph 5.12.4
3
Total estimated length
Up to 300km
Up to 190km
Average representative
1.5m
1.5m
Plough / jetting
Plough / jetting /
diameter
burial depth used for the
purposes of ES
assessment only
Burial method
No. of cable crossings
trenching
To be confirmed following
design optimisation
Cable protection area for
To be confirmed following
crossings
design optimisation
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Up to 9
Up to 3,240m2
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Table DCO.9
Section: Offshore cabling
Ref
DCO constraint
wording
Sch1,
The total length of the
Pt3,
cables comprising Work
6(2)
No. 3A shall not exceed
190 kilometres
Key flexibility arising within DCO
constraint
Comment
Ability to lay any length of cables to
shore less than 190 kilometres within
any part of the array areas or export
cable corridor
Different lengths of cables can be used
to reach any location of OSP within the
array areas
Sch1,
Pt3,
6(3)
The total length of the
Any arrangement of intra-array cables
cables comprising Work
is permitted between any location for
No. 1(e) shall not
OSP(s) or met mast
exceed 300 kilometres
Sch1,
Pt3,
6(1)
The number of cables
Any number of cables of 3 or less may
forming part of the
be installed offshore
laid in each of the
corridors forming part of
the Order limits
between reference point
AA and reference point
BB and reference point
CC and reference point
DD and the area
marked by reference
point EE on the works
plan shall not exceed
three
Ref
Sch6,
Pt2,
9(c)
Comment
Requires that a ‘construction method statement’, including details
Will allow MMO to
of cable installation is submitted to, and approved by, the MMO
agree cable burial
before marine licensed activities can be undertaken
depth
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5.13
Cable Landfall
5.13.1
The export cables from the offshore wind farm will make landfall in the
Sizewell area to the north of the existing GGOWF cables, as shown on
Figure 5.2. Up to three export cables will be laid from a specialist vessel,
most likely an anchored barge due to the shallow nature of the shore
approaches. The barge will require two attendant anchor handlers for
positioning and a tug for transiting. The programme for each export cable
lay is expected to be 25-30 days including a weather allowance (but not
including the directional drilling duct installation set out in Section 5.14).
The operations for each cable landfall will be planned to take place when a
sufficient good weather period is expected.
5.13.2
Prior to the cable landfall operations taking place, directional drilling ducts
will be installed between the landfall area and the onshore transition bays,
which are located in a field to the west of the landfall area (see Figure 5.2).
The construction of these directional drilling ducts is a separate operation to
the cable landfall works, details of which are set out in Section 5.14.
5.13.3
The cable landfall works will involve the pulling ashore of the export cables
from the offshore wind farm to the onshore transition bays through the ducts
installed by the directional drilling process. The vessel will set up in position
as close as possible to the landfall at high water and beach anchors
connected to stabilise the vessel’s position. The vessel will most likely be of
a flat bottom design and be able to ground at low tide on the seabed.
5.13.4
A few days before the vessel arrives, preparations on the beach will be
made. These preparations will include the excavation of the end of the
relevant duct during the low water period and extending the trench from the
directional drilling ducting work to low water in order to bury the cables. The
duct drawstring will be connected to a winch wire on its landward side and
the wire then pulled in a seaward direction and connected to the cable end
on board the cable laying vessel. The cable will then be pulled ashore by a
land based winch behind the transition bays. If a subsea plough is being
used to bury the cable offshore, it will be pulled ashore at the same time and
the cable loaded into it before it is pulled through the duct and into the
transition bays. It is anticipated that this process will take at most two days
to complete, from the arrival of the vessel carrying the export cable. Once
pulled through the directional drilling duct the export cable will be buried in
the intertidal and nearshore approaches.
5.13.5
With the export cable securely in position at the transition bays the export
cable vessel will commence installation of the cable across the nearshore
zone and progress along the GWF export cable route towards the offshore
substation. At the landfall the duct will be plugged and reburied. The void
between the cable and the duct wall will most likely be filled with bentonite (a
thixotropic clay) to aid dissipation of heat away from the cable. Plates 5.20
and 5.21 show examples of cable landfall works.
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Plate 5.20 Example trench to enable intertidal cable burial at GGOWF
Source: GGOWL
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Plate 5.21 - GGOWL cable pull in works
Source: Jim Hodder Associates
5.13.6
A landfall cable working area of approximately 5100sqm (80m x 64m) will be
required during the cable landfall operations. Plant used for the landfall
works is likely to include 2-3 excavators, a tractor and a winch. A temporary
beach compound (25m x 15m) within this area will be used for the storage of
plant and machinery during landfall operations. The compound will be
located above the mean high water level and will include the use of terram
matting if necessary to minimise damage to vegetation. The compound will
be fenced off from members of the public during construction activities.
Other elements of the cable working area (up to approx 50m x 50m) will be
temporarily fenced during the cable landfall operations for safety reasons.
Fenced areas will not extend over the footpath located toward the back of
the beach and the public will not be prevented from accessing other parts of
the beach that are unaffected by the cabling operations.
5.13.7
An additional area, which will partially overlap with the cable working area,
will be required at the landfall location to accommodate beach anchors. The
beach anchors will be required to anchor the offshore vessel whilst the
export cables are pulled to shore. The areas will extend approximately
100m either side of each cable being pulled. These areas would not be
fenced for extended periods; fencing would only occur during offshore cable
laying operations. Members of the public will be kept away from these areas
during cable pulling operations by security patrols.
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5.13.8
Access to the cable landfall working area will be from the existing Sizewell
Beach public car park area to the north. Two routes will potentially be used,
one located between mean low water and extending to 5m west of mean
high water and the other located further west through the dune areas. It is
anticipated that the former will predominantly be used by tracked vehicles.
The other route will be up to 4m in width, with additional passing areas, and
will be determined in the pre-construction phase of the project when the
contractor has been appointed and submitted to Suffolk Coastal District
Council (SCDC) for approval. It is proposed that temporary ‘terram’ matting
will be laid for the duration of all the beach construction operations. This will
delineate the route and reduce the potential for damage to dune habitats.
Elements of the route could also be fenced or delineated with tape if this
would not disrupt other uses of the beach and if agreed with SCDC. There
is potential to leave the terram matting on a permanent basis if agreed with
SCDC.
5.14
Landfall and Other Onshore Drilling Works
5.14.1
As noted in Section 5.13 the export cables from the landfall area on the
beach to the transition bays will pass through ducts installed by directional
drilling. The construction of these directional drilling ducts is a separate
operation to the cable landfall works and will be carried out before the
landfall works take place. The directional drilling works from the transition
bay area to the beach landfall area will take approximately 2 months. Other
onshore drilling works may be required, if open cut trenching is later proved
impracticable, during the cable laying operations from the transition bays
toward the substation and for the connection to the transmission network.
Likely locations where drilling works may be carried are shown in Figure 5.2.
The techniques employed for these other drilling operations would be similar
to those described for the directional drilling work from the cable landfall to
the transition bays.
5.14.2
The directional drilling works to create the connection between the onshore
transition bays and the directional drilling ducts on the beach will involve
drilling an arc between the two points, to pass underneath a feature to be
avoided (namely the sensitive foreshore habitats and beach chalets). Plate
5.22 provides a simplified typical directional drilling arrangement and Plate
5.23 shows an example directional drilling duct.
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Plate 5.22 Typical (simplified) directional drilling arrangement
Drilling Site
Source:
Reception Site
Balfour Beatty Power Networks Limited
Plate 5.23 Example directional drilling duct
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Plate 5.24 GGOWF HDPE ducts at the landfall
Source: Jim Hodder Associates
5.14.3
Directional drilling requires a working area at each end of the proposed drill.
One working area would be required for the drilling site and another for the
reception (exit) site. The reception site would effectively be the cable
landfall location, and the drilling site would be at the transition bay area.
5.14.4
The drilling rig and ancillary equipment will be set up on a level, firm area
approximately 20m by 15m in size. At the reception site an area
approximately 20m by 20m will be required within the cable corridor area.
There will need to be sufficient room in a direct line behind the drill exit point
to accommodate the complete length of the fabricated product pipe string.
The drilling site and reception site will require entry (or launch) and receiving
pits for each of the drilling operations. These will need to be approximately
2.5m by 1m (and 1m deep). Following completion of the directional drilling
exercise excavated materials is replaced into the pits. Where excess waste
material is generated this will be re-used or disposed of in accordance with
the site waste management plan.
5.14.5
The drilling site and the reception site will be securely fenced to ensure a
safe site, with safe access for site staff, any visitors and the emergency
services. The construction area for the reception site will be located within
the cable corridor area shown in Figure 5.2. The construction area for the
drilling site will be located within the transition bay (and associated
temporary construction area) shown on Figure 5.2. Plant and machinery will
be stored within the transition bay construction area and in the cable working
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area.
The temporary construction areas and plant and machinery
compounds will be fenced during the directional drilling operations.
5.14.6
A non-saline water supply at the drilling site will be necessary within 100m of
the drilling rig to facilitate the installation of the water based drilling mud
(bentonite, which acts as a lubricant during the process). If there is no
suitable water supply on site this can be provided by tanker.
5.14.7
A mud lagoon will be required to capture and recycle the water based drilling
mud during the drilling process and to ensure it does not exit the site. The
plan area of the lagoons may vary but will be a maximum of 5m by 5m. The
depth of the lagoons will generally be 0.8m but this may vary according to
local topography. Excavations will be plastic lined and protected with ‘Heras’
type fencing. Mud waste from this activity will be disposed of in accordance
with a site waste management plan.
5.14.8
The first stage of the drill involves a small pilot hole being drilled with a
cutting / steering head to set the path of the arc from the drilling site towards
the reception site. When the pilot bore is completed, the cutting / steering
head is replaced with an appropriately sized back-reamer at the reception
site and pulled through the pilot hole from the drill rig towards the drilling site
to enlarge the diameter of the hole. Depending on the final borehole
diameter required, it may be necessary to carry out the back-reaming in
several stages, each time increasing the borehole diameter gradually. Once
the required diameter has been drilled, the back-reamer is sent through the
bore one or two more times to ensure that the hole is clear of any large
objects and that the mud slurry in the hole is well mixed.
5.14.9
On the final pass, the product pipe (the cable ducts in this case) is connected
onto the back-reamer and the drill string at the reception site, using an
extending sealed towing head. The drill string is then be pulled from the drill
rig and retracted to the drilling site, cutting a larger diameter (clearance) bore
whilst also installing the new pipe (the cable ducts).
5.14.10 The drill process will be repeated until all required boreholes are drilled and
all of the cable ducts are installed. The directional drilling exercise between
the transition bays and the beach area will take up to two months, although
there is potential for the temporary matting on the beach access route to be
installed at an earlier stage if agreed with SCDC. The drilling operations
may extend outwith the normal construction periods for the project. This is
assessed in Chapter 26 Noise.
5.14.11 Access routes to the beach areas during the directional drilling operations will
be the same as those outlined for the cable landfall works described in
Section 5.13 and shown in Figure 5.2.
5.14.12 Two further areas of directional drilling (or similar types of drilling) are
anticipated on the cable corridor route and shown on Figure 5.2: underneath
the unnamed lane to the west of the transition bays and under Sizewell Gap.
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There is also the potential to use drilling techniques to install cables at other
points on the cable corridor if appropriate. This will be ascertained during
the detailed design phase. The principles of the construction methodology
and requirements for temporary working areas will be similar to that set out
for the directional drilling works earlier in this section. The timing of these
works is likely to be unrelated to the timing of the directional drilling work
between the cable landfall area and the transition bays.
5.15
Onshore Transition Bays
5.15.1
An onshore transition bay is where each multi-core offshore export cable is
jointed to the single core onshore cables. GWF comprises a maximum of
three export cables, and therefore requires up to three onshore transition
bays located adjacent to each other. All three transition bays will be located
in the transition bay area shown on Figure 5.2. The footprint of each
transition bay will be approximately 10-12.5m by 4m. Spacing between each
of the bays will depend on the cable arrangement up to the limit of the
transition bay area shown in Figure 5.2 and the method of construction.
Each bay will be excavated to a depth of approximately 2m with the only
evidence above ground, during operation, being access covers at ground
level for adjacent link boxes, each approximately 1.5m by 4m in size.
5.15.2
Each transition bay will either be sheet piled and structurally buffered whilst
open or the excavation sides may be battered to a safe angle of repose.
The floor of each transition bay will be concrete lined to provide a flat, clean
working environment. Near the eastern end of each transition bay will be the
directional drilling shaft for the cable run to the foreshore. This will be sealed
until the export cable is ready to be pulled into position. The other end
(west) will be the location from which the 9 onshore cables (comprising 3
cables for each multi-core subsea cable) will exit towards the proposed
substation.
5.15.3
The offshore and onshore cables will be jointed together in a controlled
environment, requiring a purpose designed container to be placed
temporarily on top of each transition bay.
5.15.4
Adjacent to each transition bay there will be a link box, which will require
permanent access during the operation of GWF. A link box contains
removable links and represents a point where the onshore and offshore
cables can be separated (electrically). This allows a cable fault to be more
easily identified within the onshore or offshore cables. Link boxes will
therefore have a number of surface level access covers and each one will be
placed in the vicinity of its associated transition bay. The area around the
transition bays and link boxes, up to 30m by 30m, will be fenced and
unavailable for other uses during the lifetime of operation.
5.15.5
A platform will be required near the onshore transition bays to support
equipment during the cable pull process from shore. This will consist of a
concrete slab approximately 5m by 5m with a shallow structure visible at
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surface level. The exact location will be finalised during detailed design,
however a position is likely to be required some 20m beyond the transition
bays in a roughly westerly direction, dependent on the final alignment of the
directional drilling ducting. It is anticipated that the structure will be removed
after completion of cable installation, although it could be retained within the
fenced transition bay area for operational access, depending on its
confirmed location during the detailed design phase.
5.15.6
The total working area for the onshore transition bays will be approximately
75m by 75m and will include space for temporary portacabins, lay down
areas, vehicles and other necessary construction and installation equipment
required during the construction of the transition bays.
5.15.7
A permanent new access track will be required between the transition bay(s)
and Sizewell Gap. The proposed location of the access track is shown on
Figure 5.2.
5.16
Onshore Cabling
Onshore cable route
5.16.1
The principle onshore electric cable routes are shown in Figure 5.2 and
comprise:

The 132kV GWF export cable corridor which will run from the landfall
to the GWF 132kV compound;

The cable corridor between the GWF compound and the transmission
compound;

The 400kV transmission cable corridor between the transmission
compound and the two sealing end compounds; and

The 132kV transmission cable corridors between the transmission
compound and the existing National Grid Electricity Transmission
(NGET) 132kV cable corridor from the GGOWF Leiston A substation
to the existing 400kV/132kV substation at Sizewell (one corridor
heading south east and the other towards the existing Leiston A
substation).
5.16.2
The 132kV GWF export cable corridor from the landfall to the transition bays
will consist of three multi-cored cables located within a permanent cable
corridor of 38m in width with approximately a 10m gap between the cables.
The gap between the cables will reduce as the cables approach the
transition bays.
5.16.3
The majority of the 132kV GWF export cable corridor between the transition
bays and the GWF substation passes through agricultural land under arable
cultivation. A 38m wide working corridor will be required along the length of
the cable corridor where open cut trenching takes place. Figure 5.2 shows
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the location of the corridor where a permanent cable easement of 23m
(open trenching) or 33m (directional drilling) would be required. The cable
corridors have been identified, but the precise location of cables within those
corridors will be subject to detailed design and feasibility assessment. The
working width for open cut trenching will comprise:
 A set of three trenches with a total width of approximately 13m;
 Construction access for vehicles, which needs to allow the safe
tracking of construction vehicles in two directions. This will
comprise 5m in each direction;
 Spoil storage (15m in width); and
 Fencing.
5.16.4
The aim will be to utilise continuous cabling between the transition bays and
the GWF onshore substation. However it is possible that two cable sections
will be required for each of the export cables and jointed together at a joint
box. Consideration would be given to locate any joint boxes close to field
boundaries (subject to remaining in the identified corridor) to minimise any
impact to agricultural activities.
5.16.5
The 400kV transmission cable corridor is the principal means of connecting
GWF to the national transmission system. The cable corridor runs between
the transmission compound and the sealing end compounds and passes
through the northern extent of the Sizewell Wents block of woodland. A
cable corridor working width of 19m will be required which would comprise:
 Cable trenches of approximately 2.5m width;
tracking of construction vehicles in two directions. This will
comprise a 10m width located between the cable trenches.
This area will also be used for spoil storage;
 Fencing; and
 A permanent easement on the outside of the two cable
trenches of 2m width.
5.16.6
The 132kV transmission cable corridor connecting to the existing NGET
132kV cable corridor from the GGOWF Leiston A substation to the existing
400kV/132kV substation at Sizewell is necessary to meet National Grid’s
requirements for security of supply. The cable corridor comprises two
routes, effectively severing two existing circuits and diverting them via the
new transmission compound. A cable corridor working width of 19m will be
required which would comprise:
 Cable trenches of approximately 5m width;
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tracking of construction vehicles in two directions. This would
comprise a 10m width located between the cable trenches.
This area would also be used for spoil storage;
 Fencing; and
 A permanent easement on the outside of the two cable
trenches of width 2m.
5.16.7
Where the 132kV transmission cable corridor approaches the transmission
compound the width of the corridor has been reduced locally from 19m to
15m to minimise tree loss over the short length of corridor where it has a
north - south alignment at the western edge of Sizewell Wents. The
reduction in width over this short length is achievable by a localised
reduction in access width (due to the access available via the permanent
access road), localised spoil management and the potential likelihood of
drilling due to ground levels in this area. Spoil from this element of the cable
corridor may need to be stored elsewhere within the cable corridor or in the
substation construction area.
5.16.8
The 132kV transmission cable corridor includes jointing areas where the
proposed 132kV cables are joined to the existing 132kV transmission cables
which run from the existing Leiston A compound to a substation on Sizewell
B. These jointing areas are located to the south of the existing Leiston A
substation and to the south (but unconnected to) of the eastern sealing end
compound. The cable corridor in these areas has been widened to allow for
underground jointing bays and associated works in these areas.
5.16.9
Other cables are required to connect between the compounds, including a
Distribution Network Operator (DNO) connection from an existing supply
near the entrance to the GGOWF compound, to both the GWF and
transmission compounds. The other cable corridors also leave the ability for
a 132kV circuit to run directly between the GWF compound and the existing
Leiston A substation to allow a phased completion of the connection to
progress if required.
Cable corridor site preparations
5.16.10 The working cable corridors will be suitably fenced; the type of which will
depend upon the farming activities and discussions with the landowner.
5.16.11 Protection of topsoil will be ensured during the construction phase and the
ground reinstated to its former condition on completion. Generally topsoil
will be stripped from the working corridor using 20t tracked 360 degree
excavators and stored to one side in the area allocated. Subsoil will then be
removed and stored separately. When backfilling trenches after cable
installation, subsoil will be interred first, followed by topsoil. Topsoil will not
be stripped from the area where it is stored.
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5.16.12 In most cases the construction haul road along the working corridor will
require no additional preparation other than topsoil stripping. However in
certain circumstances, such as poor ground conditions, temporary surfacing
such as hardcore, geotextiles or re-useable plastic surfacing may be
necessary.
5.16.13 In some locations it may only be necessary to strip the topsoil from the
actual trench width, with the remaining working corridor being protected by
means of temporary surfaces to protect the underlying soil structure.
Open trench cable installation methodology
5.16.14 Following the cable corridor preparation works, excavation of the cable
trench will commence using a mechanical excavator. The cable trench width
and depth will be approximately 2m by 2m. Dumper trucks will be used to
transport material to and from the storage areas. Any surplus spoil will be
taken off site and disposed of in accordance with the appropriate waste
carrier licence as detailed within a site waste management plan. Parts of the
cable corridor will require some tree felling (through Sizewell Wents).
5.16.15 Cable installation may be undertaken using a mole plough. This allows the
cable to be installed without the need to dig a trench. As the mole plough is
dragged through the ground, it leaves a channel deep under the ground,
within which the cable is laid.
5.16.16 Cables may be installed in ducts to allow for future ease of maintenance and
to reduce ground disturbance should cables need to be replaced during the
operational life of the wind farm. Consideration will be given to the
installation of a spare duct(s) within the cable trenches to facilitate
rectification of the fault without necessarily removing the faulty cable from its
duct.
5.16.17 Other cables which could be included in the cable trenches include:
 a fibre optic communication cable and duct
 an earth conductor cable duct (subject to detailed earthing
system design)
 a cable monitoring system (subject to detailed design)
Reinstatement
5.16.18 Following completion of the cable system installation, the working area will
be reinstated to its previous condition. This will include:
 Reinstatement of foreshore;
 Reinstatement of topsoil; and
 Reseeding of any fields of grassland, grass margins and ditch
banks (except where forming part of other new works by
GWF).
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5.16.19 Table 5.7 provides a summary of the onshore cabling system.
Table 5.7 Summary of the onshore cable system
Key onshore cable system characteristics
Up to 3 multicore cables between landfall
and transition bays
132kV export cables
Up to 9 single core cables from transition
bays to GWF compound
132/400kV transmission cables
2 sets of 3 single core cables
Transition bay permanent fenced area
30m x 30m
Total working area footprint of transition
5,619m2
bay area
Export cables (land fall to transition bays):
260m
132kV export cables (transition bays to GWF
compound): 816m
400kV transmission cables (transmission
Onshore Cable Corridor lengths
compound to sealing end compounds): 275m
(approximate)
to western sealing end compound
395m to eastern sealing end compound
132kV transmission cables (transmission
compound to existing 132kV cables and
Leiston A): 515m
Joints pits (if required for jointing cables
Up to 3
beyond the transition bays)
Open trench, with directional drilling
Trenching technique
proposed for 2 road crossings, between
cable landfall and the transition bays and
potentially at other locations
Typical cable depth
1-2m (minimum of 0.9m deep)
Open trench:
Permanent cable corridor width
23m (GWF 132kV)
19m (Transmission 132/400kV)
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Key onshore cable system characteristics
Directional drilling:
33m (GWF 132kV)
38m (GWF 132kV)
Cable trench corridor working width
19m (Transmission 132/400kV), reducing to
15m in one location with specific
construction/working arrangements
5.17
Onshore Substation
5.17.1
In order to control and facilitate the export of electricity from the wind farm to
the 400kV national electricity transmission network GWF will require a new
132kV compound to be built near Sizewell, the ‘GWF compound’.
5.17.2
Transmission infrastructure will also be required in order for electricity to
convert from 132kV to 400KV and to reach the existing transmission
network. As such, a 132kV/400kV ‘transmission compound’ and ‘sealing
end compounds’ will also be required adjacent to existing overhead lines in
the Sizewell area.
5.17.3
The GWF compound and the transmission compound will be located
adjacent to each other (with a distance of 10m between the boundary
fencing of each compound) and together are referred to as the ‘GWF
substation’. The GWF substation will be located approximately 1km inland
on the Suffolk coast near Sizewell, to the north of Sizewell Gap, immediately
to the west of the existing GGOWF substation site (see Figure 5.2). An
aerial view of the existing GGOWF substation is shown in Plate 5.25 to give
an indication of the type of equipment that may be present.
5.17.4
The substation will have a platform level of 9m AOD or lower. The maximum
height of equipment and buildings which will be installed within the GWF
compound is 14m and within the transmission compound is 13m, as shown
in Figure 5.6. The exceptions to these height limits are lightning protection
systems and communications masts as detailed below.
5.17.5
The GWF Preliminary Environmental Report included the potential to install
lightning protection in the GWF substation in the form of lightning masts up
to 22m in height. Subsequent detailed electrical analysis has shown that
freestanding masts are not required and that sufficient lightning protection
can be incorporated through the addition of 50mm diameter lightning rods
mounted up to 3m height on top of taller structures within the site (i.e.
reaching up to 11m or 17m AOD respectively for different areas of the GWF
compound. The details of any new GWF communications equipment will be
included in the detailed design drawings that are subject to subsequent
approval by SCDC.
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The GWF substation footprint
5.17.6
The footprint of the GWF substation sits predominantly within arable land
although it also includes part of a block of woodland (Sizewell Wents). In
addition, part of the proposed landscape mitigation area and parts of the
GWF substation encroaches into Broom Covert (a block of semi-natural
grassland used predominantly for grazing). The substation platform will be
9m AOD or lower.
Table DCO.10
Section: Onshore substation
Ref
DCO constraint
wording
Sch1,
No building forming part
Pt3,
of Work Nos. 6, 9A, 9B
19(3)
or 11, shall exceed the
relevant height limit for
constraint
Comment
Each of the works items may occupy
In practice, an
any height up to the maximum
electrical substation
permitted and at any location,
is a collection of
potentially covering the entire area.
discrete operational
its proposed location
elements, separated
specified on the height
by service corridors
restriction plan above
and maintaining safe
the approved floor level
electrical
for that location
clearances. As such
dense development
of the entire
‘envelope’ would not
occur, except where
control buildings are
proposed.
Sch1,
Pt3,
19(4)
The floor level of Work
Any floor level (for the GWF and
The proposed
Nos. 6 and 11 shall not
transmission compounds) below 9m
landform seeks to
be higher than 9 metres
AOD is permitted
achieve a balance
AOD
for a floor level in the
order of 8-9m.
Whilst lower floor
levels are permitted,
it is unlikely that this
would be pursued
except in small
areas, if required for
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construction
reasons. The lowest
possible level is
governed by
clearance to existing
groundwater.
5.17.7
Although GWF and GGOWF have the same potential maximum installed
MW capacity and are located in similar geographical locations there are
significant differences between the two, necessitating an increase in the land
included in the consent application for the GWF substation compared to the
GGOWF substation. The most significant reasons for this increase in size
are listed in the following sections.
5.17.8
Increase in harmonic filters requirements: Accurate specification of
harmonic filters to be installed in the GWF substation onshore can only be
completed once the final parameters of electrical systems (turbines,
transformers, cables, reactive compensation) are available and once the
harmonic injection limits are provided by NGET - the system operator. The
harmonic limits are allocated by the grid operator to projects on a first come
first serve basis. Available harmonic injection limits in the Leiston/Sizewell
location were largely ‘consumed’ by GGOWF project and the remaining
headroom for GWF is expected to be much tighter. It is reasonable to
assume that rating of harmonic filters may increase by 100% - 200% as
compared to the GGOWF project. This will result in a larger area for
harmonic filters in the GWF substation compared to the GGOWF substation.
5.17.9
Alternative technologies: There are various technologies available on the
market to provide the characteristics and functionality required from the
GWF onshore substation. The technologies may differ quite considerably in
terms of size but also capital cost, O&M requirements, system availability,
H&S hazards etc. The technology used in GGOWF project for the reactive
compensation (Siemens SVC +) tends to be on the lower end of the
available options in terms of the footprint requirements, also HIS switchgear
used by Siemens is one of the most compact designs available on the
market. Therefore it has not been assumed that only equipment with the
smallest possible available footprint will be used as this would curtail both
onshore and offshore procurement options.
5.17.10 Unknown reactive power capability of Wind Turbine Generators
(WTGs): GGOWF wind farm uses a significant amount of reactive power
from its specific turbines reducing the rating/size of the onshore equipment
to deliver the NGET code/STC obligations. Before final WTG selection for
the GWF project it cannot be assumed that a similar capability will be
available from procured turbines and that a similar technique will be
possible. At this point it is assumed that turbines will always operate at unity
power factor (as per minimum NGET Code requirement) and all necessary
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reactive power will be delivered from the plant onshore. It is expected that
the rating of the reactive compensation for the GWF project may double as
compared to the GGOWF project to cope with these increased
requirements.
5.17.11 Different cable parameters: Although the installed capacity of GWF is of a
similar size and located close to GGOWF, there may be a significant
difference in the final cable parameters used in both wind farms. The
differences may be caused by cable design (e.g. insulation materials,
armouring etc.) and potentially bigger cable size (i.e. to cope with increased
reactive power flow from the wind farm). Alternative cable parameters may
increase charging currents by up to 20% and necessitate a further increase
of the rating of reactive compensation installations onshore.
5.17.12 Equipment make: Similarly as per the previous section, equipment of the
same rating and class may differ in size when sourced from alternative
vendors. Based on the experience from other projects, some suppliers tend
to yield a smaller footprint than similar equipment from other manufacturers.
5.17.13 Substation accessibility / maintainability: Health and safety systems and
considerations are continually reassessed and evolving. On detailed design
of the GGOWF substation it was found that limited space was available in
the GGOWF onshore substation and as a result the equipment within the
site was very densely installed.
GWF has to achieve acceptable
consideration of health and safety aspects of the development on a risk
basis and consider all practicable options to reduce risk. This includes
allowing sufficient space between the plant, and width of paths and roads
within the substation, to afford safer and easier access to all parts of the
system without de-energising other system components (as has to occur in
the GGOWF substation).
5.17.14 As discussed above there are factors significantly affecting the rating and
size of apparatus to be installed in the GWF onshore substation. GWF has
commissioned an indicative design from a major supplier to develop a draft
onshore design for the GWF compound to allow a realistic estimate of the
compound footprint to be calculated. Based on this work the expected land
take for the GWF compound is 2.2ha and the assessments have been
undertaken in accordance with this.
5.17.15 The size of the transmission compound required to connect GWF to the
onshore transmission network is also expected to increase in size as
compared to the substation serving GGOWF (called Leiston A). NGET
utilises the pre-existing super grid transformers (SGTs) and 400kV
switchgear located within Sizewell B power station for the GGOWF
connection but this infrastructure has insufficient spare capacity to
accommodate the expected output of GWF. Therefore additional SGTs and
switchgear will be required within the new transmission compound, as well
as the 132kV switchgear that was required for GGOWF.
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5.17.16 There is a greater level of certainty on the equipment that will be installed in
the transmission compound than in the GWF compound as the transmission
compound is not dependent on the type of WTGs that are installed. Also
NGET construct a significant number of transmission compounds compared
to offshore wind farm compounds that have been previously built. This not
only leads to greater certainty on design, but also means that NGET have a
number of preferred suppliers, making it easier to determine the size of the
equipment.
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Plate 5.25
Aerial photo of existing GGOWF substation (looking west), showing both the GGOWF compound and NGET’s Leiston A
compound (left side)
Source:
GGOWFL
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GWF compound
5.17.17 The dimensions of the GWF compound will be 170m by 130m (c. 2.2ha) with
a maximum height of up to 14m, excluding lightning protection rods of up to
17m (see Figure 5.6). Only a small proportion of the buildings and
equipment in the compounds is expected to be up to 14m in height. The
design of the lightning protection system is dependent on the equipment that
is included within the substation but, if required, would be no taller than 3m
above any structure and no greater than 50mm diameter for each protection
rod.
5.17.18 The final design and equipment to be installed in the GWF substation will not
be known until after a decision can be made on which WTGs are to be used
in the project. However it is possible to ascertain the generic types of
equipment that are likely to be required.
5.17.19 The GWF (132kV) compound will comprise up to three electrical bays. The
typical equipment within each electrical bay includes:
 132kV SF6 switchgear1;
 Transformer(s);
 Reactive compensation, to include;
o Dynamic reactive compensation, e.g. SVC,
STATCOM;
o Mechanically switched capacitors; and
o Mechanically switched reactors.
 Harmonic filters.
5.17.20 Table 5.8 provides a summary of the GWF compound.
Table 5.8 Summary of the onshore GWF compound
Key project characteristics
Compound area (fenced area)
2.2ha
Finished floor level
9m AOD or lower
14m
Maximum building/electrical equipment
height
(75% of site constrained to 8m maximum
height above platform level)
1
switchgear for all bays may be combined and housed in a single building
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Number of electrical bays
Up to 3

132kV SF6 switchgear2;

Transformer(s);

Reactive compensation, to include;
o
Dynamic reactive
compensation, e.g. SVC,
STATCOM;
o
Mechanically switched
capacitors; and
o
Mechanically switched
reactors.
Typical components within each bay
Other substation elements

Harmonic filters

Interconnecting cables;

Access tracks, gravel paths and
hard standing;

Security fencing

Lightning protection rods extending
up to 3m above buildings or
components (maximum 50mm
diameter)

Earthing mat

Permanent and temporary utilities

Control buildings;

Car parking;

Communications mast;

Lighting;

Dump tanks;

Water tank;

Back up diesel generators; and

Welfare facilities.
Transmission compound
5.17.21 The dimensions of the transmission compound will be 70m by 130m (0.91ha)
with a maximum height of up to 13m (see Figure 5.6).
5.17.22 The design of the transmission compound is known with more certainty than
that of the GWF compound as it does not require prior knowledge of what
WTGs will be used. The DCO application therefore includes a layout for
2
switchgear for all bays may be combined and housed in a single building
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approval with respect to the transmission compound. In the event that this
layout is varied (and subsequent approval sought from the local planning
authority), the location of the taller buildings and equipment will be bound by
the height limits shown in Figure 5.6.
5.17.23 The (132kV/400kV) transmission compound and associated infrastructure will
include:
 132kV and 400kV switchgear;
 Two 400kV / 132 kV supergrid transformers;
 Control, communication and monitoring equipment; and
 Cable sealing compounds and gantries to connect to the
existing overhead transmission lines.
5.17.24 The transmission compound will be enclosed by a fence surrounding the
external equipment outlined above. Other infrastructure and equipment will
be included within the compound such as interconnecting cables, access
tracks, hard standing, car parking, water tanks, communications mast, diesel
generators and welfare facilities as listed in Table 5.9.
5.17.25 Table 5.9 Summary of the onshore transmission compound
Compound area
0.91ha
Finished floor level
9m AOD or lower
Maximum building/electrical equipment
13m
(more than 50% of site constrained to 11m)
height

132kV and 400kV switchgear;

Two 400kV / 132 kV super grid
transformers;

Control building;

Interconnecting cables;

Access tracks, gravel paths and
hard standing;

Internal substation roads;

Car parking;

Earth mat;

Lighting;

Communications mast;

Dump tanks;
Typical substation components
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
Water tank;

Back up diesel generator;

Welfare facilities; and

Security fencing.
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5.18
Landform
5.18.1
As part of the proposed GWF substation a profiled landform will be built
around the north, west and south sides of the GWF compound. The
landform (and lowering the floor level of the substation) has been included as
a result of consultation with local authorities and the local community to
reduce landscape and visual effects. The landform adjoins open fields and
will be built using material generated from excavation to lower the substation.
The landform will provide immediate screening of the substation. Tree
planting will also take place on the landform to further screen the substation
over time as the trees mature.
5.18.2
Two potential landforms have been included in the application: one in the
case of a Compulsory Purchase Order being required; the other if a
commercial agreement can be reached with the relevant landowner.
5.18.3
In the case of a Compulsory Purchase Order being required the landform will
be as shown in Figure 5.2. To the south of the substation the height of the
landform will vary from 15.5m AOD to 17m AOD, with the higher elements of
the landform corresponding to the higher elements of the GWF compound.
To the west the landform will be 15.5m AOD and to the north it will vary from
13.5m AOD to 16m AOD. The variation in the height of the landform to the
south and north will allow it to merge better with the existing landscape and
has been shown in response to ongoing consultation with the relevant local
authorities. The maximum heights shown in Figure 5.6 will be allowed to
vary by -100mm to +300mm to allow for construction tolerances and
variation. The outside slopes of the landform, i.e. the aspects of the landform
that will be seen will have an average slope of 1 in 10. The dimensions of
this landform have been agreed with the relevant local authorities as the
minimum required and is therefore a suitable proposal for a Compulsory
Purchase Order.
5.18.4
If a commercial agreement can be reached with the landowner, GWFL will
seek to extend the landform approximately 50m further south at its maximum
extent to slacken the slope further to 1 in 16. This is shown in Figure 5.2
(area in the key labelled as “subject to commercial agreement”. The
maximum heights on the landform will be similar for both the Compulsory
Purchase Order and the commercial agreement scenarios.
5.18.5
Whichever scenario is progressed it will be completed in accordance with
landscape mitigation principles, further details of which are included in the
Onshore Construction Code of Practice (document reference 5.3.1). The
principles include planting the landform with woodland and woodland edge
species suitable to the local area and returning the lower slopes of the
landform to arable and grassland as appropriate to the existing land use. A
typical cross section is included in Plate 5.26.
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Plate 5.26 Typical landform and planting profile
5.18.6
Filter drains would be included on the inside toe of the landform to collect any
run-off and prevent any ponding within the compound, which is dug-into the
natural topography. For the outer toe of the landform, surface water run-off
will naturally shed across the fields and infiltrate into the ground.
5.18.7
Further information regarding the landform and other proposed landscaping
is provided in Chapter 20 Seascape, Landscape and Visual Character.
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5.19
Sealing end compounds, gantries and overhead wires
5.19.1
National Grid propose to connect the proposed transmission compound to
the national transmission system by converting the existing towers (pylons) to
the east of the existing GGOWF substation (towers 4ZX002 and 4ZW002)
into tee-off towers and installing downleads into sealing end compounds at
each tower, connecting to the transmission compound via underground
cables. For electrical proximity/safety reasons the tee-off circuits must be
from the outer circuits at each tower. Two sealing end compounds will
therefore be required, one adjacent to each of the existing towers. The
400kV transmission cable will be brought to the surface within the sealing
end compounds and connected to the overhead lines via a gantry system.
5.19.2
The location of each of the sealing end compounds and the equipment these
will contain is shown in Figure 5.2. The final location of the equipment is
subject to micrositing at the detailed design phase due to the need to ensure
safety distances between the different phases of the electrical equipment and
from the compound fence. The exact location of the compound fence is also
reliant on detailed civil engineering works. Although the exact location of the
individual pieces of equipment may vary within the compounds the general
arrangement will be very similar to that shown in Figure 5.2. As with the
GWF compound a maximum finished floor level and height has been
assumed for the assessments in the ES and is set out in the following
paragraphs.
5.19.3
The western sealing end compound will have approximate dimensions of
32m by 40m and an area of 0.22 ha. The western sealing end compound will
have an approximate finished floor level of between 7.7m to 8.3m. The
maximum height of founded equipment within the western sealing end
compound is the top of the gantry which will have a maximum height of 13m
above the floor level.
5.19.4
The eastern sealing end compound will have maximum dimensions of
approximately 25m by 40m and an area of 0.19. The eastern sealing end
compound will have an approximate finished floor level of between 6.7m to
7.3m. The maximum height of founded equipment within the eastern sealing
end compound is the top of the gantry which will have a maximum height of
13m above the floor level.
5.19.5
Work at the sealing end compounds will include:
 Installing one set of downleads to gantries at each tower (4ZX002 and
4ZW002);
 Modifying two sets of crossarms (Bramford - Sizewell 3 and Bramford
- Sizewell 1 circuits);
 Installing temporary access roads and crane/mobile elevating work
platforms to each tower working area; and
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 Installing an Equipotential Zone at each working area.
5.19.6
Three 400kV downleads will be connected to the overhead lines at each
tower via modified cross arms and new gantries. The gantries will be located
in each sealing end compound and will be a lattice structure similar to that
shown in Plate 5.27. The gantries will be up to 13m in height. Modification
or replacement of the existing transmission tower cross arms will be required.
5.19.7
The existing cross arms will be modified by having box cross arms added.
5.19.8
The Equipotential Zone in each working area will consist of metal mats which
all the equipment and operators stand upon during any work with the
overhead line. This will lower the risk of electric shocks.
Plate 5.27 - Example sealing end compound and gantry connection to overhead
lines
5.19.9
The sealing end compounds will be contained by a fence.
Other
infrastructure and equipment will be included within the compound such as
hard standing and electrical equipment to connect the 400kV export cable to
the gantries. A summary of the sealing end compounds is included in Table
5.10.
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Table 5.10 Summary of the sealing end compounds and gantries
Western compound:
Compound area
Eastern Compound:
Total area of 0.4ha
Western compound: 8.1m
Finished floor level (approximate)
Eastern Compound: 6.8m
Maximum height
(excluding overhead lines, their
13m (gantries)
connection to the gantry, and cross arms)
Tower
Replacement cross arms required
Other components
5.20

Security fencing

Hard standing

Drop leads

Electrical connection equipment
Other onshore infrastructure
Replacement GGOWL Telecommunications Mast
5.20.1
The GWF substation will, in part, be located on the site of an existing
telecommunications mast used by GGOWL. The telecommunications mast
(a wood pole) and dish provides the primary control link between GGOWF
and its control centre. Provision is therefore included in the application to
remove and replace this communications mast. The location of the
replacement GGOWL communications mast is shown in Figure 5.2 along
with a cable linking the mast to the GGOWL substation (shown as ‘other
cable corridors’ in Figure 5.2). The dish of the communications mast will be
up to 15m in height and attached to a wood pole located to the front of the
retained Sizewell Wents woodland. The wood pole could be up to 16m in
height. An image of the current mast is shown in Plate 5.28.
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Plate 5.28 – Current GGOWF telecommunications mast
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Table DCO.11
Section: Relocated telecommunications mast
Ref
DCO constraint
wording
constraint
Sch1,
The height of the
Any height for the equipment and pole
Pt3,
relocated
up to 15m and 16m respectively is
19(3)
communications mast
permitted.
Comment
The maximum
height is likely to be
utilised to maximise
shall not exceed 15
transmission
metres AOD, and its
certainty.
supporting pole shall
not exceed 16 metres
AOD
Local electricity supply
5.20.2
The substation and sealing end compounds will need to be connected to the
local District Network Operator (DNO) electricity supply in order to run
essential services such as lighting. The provision of this DNO supply
requires the erection of a DNO transformer (located in the ‘DNO area
(including transformer)’ shown on Figure 5.2). The transformer will be
connected by underground cables to the existing DNO supply located to the
east of the existing GGOWF substation. The DNO transformer will be within
a container of dimensions up to 3m by 3m by 3m. The remainder of the DNO
area will be covered in a permeable surface or chippings to allow access to
the transformer.
5.21
Summary of onshore infrastructure permanent and temporary footprint
Table 5.11 Summary of substation permanent and temporary footprint
Development element
Total area
Permanent footprint
Substation
3.1ha
Sealing end compounds
0.4ha
GWF transition bays
0.3ha
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Development element
Total area
New permanent access roads, turning area and drainage
0.5ha
reserve
Screening landform
6.9ha(3)
Security area around substation
0.4ha
Total
11.7ha
Temporary footprint
Beach working areas
2.0ha
Beach access
1.1ha
Cable corridor inland of beach/dune to GWF substation
4.4ha
(working corridor including transition bays and assuming open
cut trenching)
400kV cable corridor between transmission compound and
0.7ha
sealing end compounds
132kV cable corridor between transmission compound and
0.8ha
joint with existing Leiston A 132kV cables
Substation and sealing end compounds temporary laydown
8.2ha
areas (excluding land already covered within cable corridor)
Screening landform (areas returned to existing land use)
1.9ha
Access roads and service reserves
0.4ha
Total
19.5ha
3
If the land is not agreed by private agreement then the screening landform will be 6.0ha.
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5.22
Project Programme
5.22.1
Typical timescales for a scheme of the scale of GWF are provided in Table
5.12. The final construction programme will be a function of many logistical,
contractual, practical, supply chain and electrical (including outages)
influences. The table therefore provides indicative timescales for such a
project, assuming that all aspects of the project are unhindered by
unforeseen circumstances and a single-phase approach is adopted. A
subsequent explanation is provided on how timescales have been addressed
in the assessments.
Table 5.12 Example timescales for a 500MW scale offshore wind farm
Activity
Typical length
Indicative
commencement
Indicative
completion
Grid construction4
30 months
Q2 2013
Q3 2015
Offshore foundations5
18 months
Q2 2015
Q3 2016
Offshore cables6
27 months
Q2 2015
Q2 2017
Offshore topsides7
27 months
Q2 2015
Q2 2017
Commissioning and
12 months
handover
5.22.2
Q2 2017
Q2 2016
Table 5.13 assumes an ‘ideal’ single-phase programme for a scheme of the
scale of GWF, therefore it is essential that a deliverable project programme is
afforded sufficient flexibility beyond this to accommodate unforeseen events,
including, but not limited to:
 Variations in ground conditions;
 Critical logistical and supply chain constraints or delays;
 Delays to arrival, or failures, of specialist equipment;
 Changes to National Grid outage dates.
5.22.3
Whilst GWFL have extensive knowledge of potential risks to programme in
relation to both the offshore and onshore works and an ability to manage
them wherever practicable, the assessments have necessarily considered
4
Encompasses all onshore sub-station construction, cable installation and NGET transmission system
works
5
Includes all WTG and ancillary infrastructure foundations
6
Includes export, inter and inter-array cable works
7
Includes all WTG components and topsides of ancillary infrastructure
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the implications of a longer overall programme. The cumulative assessment
of each aspect also considered, where necessary, the real time impacts of an
altered commencement date.
5.22.4
To provide a sound base for assessment the following criteria were chosen:
 Overall offshore construction window of 56 months (permitting
all forms of offshore works, except for piling which is subject to
a seasonal restriction), notionally assuming a Q2 or Q3 2015
commencement;
 Total maximum piling duration of 39 months, notionally
assuming an earliest Q2 or Q3 2015 commencement within the
56 month offshore construction window;
 Overall onshore construction window of 60 months;
 Landfall directional drill period of 2 months;
 Cable pulling periods (up to 3 no.) of 1 month each.
5.22.5
Each assessment also considers, where appropriate, the potential impact of
a change in when the above windows could occur, rather than their assessed
relationship to commencement of the main offshore works in spring 2015.
5.23
Offshore Pre-construction and Construction
5.23.1
Construction of the offshore works will generally be completed in a number of
stages, which are as follows:
 Pre-construction surveys;
 Prefabrication (structures constructed onshore);
 Transportation (structures floated or transported by
transportation vessels);
 Offshore foundation structure installation;
 Offshore substation installation and commissioning;
 Inter and intra-array cabling;
 Transitional pieces installed;
 WTG installation;
 Cable landfall works;
 Export cabling; and
 Commissioning.
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5.23.2
Installation of the offshore elements will primarily take place outside of the
winter months due to potential adverse weather conditions, which increases
the risk of delays in activities and excessive costs. The main offshore
construction season is likely to extend from March to November each year
depending on the vessels chosen by the construction contractor, although
consideration would still be given to working outside of this envelope if
practicable, safe and (where appropriate) in line with the seasonal piling
restriction. Offshore construction works will normally be carried out on a 24
hour operations basis.
5.23.3
A two season programme is likely to be adopted. In the first season
installation will also include all of the navigational aids required to ensure
navigational safety, as laid down in the appropriate guidelines (see Chapter
16, Shipping and Navigation). The commissioning programme will then
take place throughout both construction seasons, as the WTGs will be
brought online sequentially.
5.23.4
The project timetable will ensure that any seasonal restrictions on certain
activities identified during the consenting process are adhered to. Subject to
all consents for the project being received during late 2012, it is anticipated
that the GWF project would be constructed in 2013 – 2016 though this will be
influenced by a number of factors.
5.23.5
Table 5.14 summarises the indicative suite of construction vessels and
vehicles that will be utilised for the construction of offshore components of
GWF.
Table 5.14 Construction activity summary
Construction
aspect
Detail
Pre-construction
Dedicated geophysical survey vessel using side scan sonar,
geophysical survey
multibeam echosounder and magnetometer. Will survey GWF site,
export cable corridor and landfall site.
Pre-construction
Dedicated geotechnical survey vessel taking a number of boreholes,
geotechnical survey
cone penetration tests (CPT) and vibrocores within the GWF site,
export cable corridor and landfall site.
Pre-lay grapnel run
Dedicated vessel with PLGR device and ROV
Plough trails
Cable installation vessel along with selected installation equipment
(plough, jetting ROV and or trencher).
WTG and ancillary
Foundation installation HLV / jack-up barge, possible grouting vessel,
infrastructure
possible foundation transportation vessel and possible support
foundations
vessels
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Construction
aspect
Detail
.
Scour protection
Construction barge or dedicated rock placement vessel
WTGs
HLV or jack-up barge
Ancillary structures
HLV or jack-up barge, substation installation vessel
(OSP, collection
station,
accommodation
platform and met
mast)
Cable lay
Cable lay barge/ vessel
5.23.6
The physical footprint on the seabed from the construction vessel activity will
come from a number of sources including PLGR work, jack-up barge legs,
anchor placement (if DP vessels not used), cable plough/trencher/jetting
machine and will be dependent on the method utilised and the number of
movements required (dictated by the WTG option taken forward and site
layout). A jack-up barge will have between four and six legs with a footprint
of approximately 10m2 per leg. The anchor vessels will have between four
and six anchors each, with the anchor size being approximately 2 – 4m2.
5.23.7
In addition to these main vessel movements, there will also be significant
levels of activity undertaken by smaller support vessels, including:
 Tow barges;
 Anchor handling tugs;
 Offshore supply vessels;
 Crew vessels for personnel / equipment transfer;
 Standby vessels; and
 Guard vessels.
Construction logistics, management and security
5.23.8
During marine operations a safety zone will be applied for to cover the
construction, commissioning and operational phases of the project.
5.23.9
The purpose of a safety zone will be to manage the interaction between
vessels and the wind farm in order to protect life, property and the
environment. The fundamental principle is that vessels will be kept at a safe
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distance from construction, commissioning and operational activities related
to the wind farm, in order to avoid collisions.
5.23.10 A 500m safety zone (the maximum permissible under international law) is
very likely to be in place around each turbine during the construction phase.
The safety zone will be monitored and controlled by the Project with the
support of a Marine Control Centre.
5.23.11 During construction, wind farm extremities are generally marked with
standard cardinal marks, and in areas of high traffic density guard vessels
may also be employed. The requirement for such measures are set out in
the International Association of
Lighthouse Authorities (IALA)
Recommendation O-117 on ‘The Marking of Offshore Wind Farms’ (as
detailed under Section 5.23 below). Jack-up barges and HLV whilst
‘engaged’ in construction work will be lit in line with the requirement of IALA
Recommendation O-114 on the Marking of Offshore Structures. Specific
detail on that proposed for GWF is provided in Chapter 16 Shipping and
Navigation.
Pollution prevention
5.23.12 Pollution prevention will be controlled and mitigated from the design stage
onwards. For example, the WTG nacelle frame is typically designed and
manufactured with an incorporated bund which can hold the full oil content of
the gearbox in the event of catastrophic failure. Additionally, if any oil filled
transformers are used, the area will be bunded to contain any oil leaks.
5.23.13 The staff and vessel crew will be trained and equipped to use spill kits in the
event of a breach of containment occurring. This will be defined by GWFL at
the appropriate juncture and would be governed by a full Risk Assessment
and Method Statement process. Additionally the work relating to the WTG
will be specifically controlled and managed via Wind Turbine Safety Rules .
5.23.14 There will also be a waste management procedure which will be
administered and managed to ensure it is strictly adhered to by site staff,
contractors and visitors to the wind farm.
5.23.15 In the event of the safe system of work failing or a catastrophic incident
occurring the appropriate arrangements will be in place to control, manage,
recover and dispose of any contaminants and dropped objects (as
applicable).
Construction ports
5.23.16 GWFL are not in a position to make commitments with regard to any
particular ports at this stage. The choice of construction ports used for the
GWF project will be driven by the contractual placements for the wind farm
components and availability of sufficient port space.
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5.23.17 It is envisaged that a local port will be selected by the GWF project principal
contractor based on suitability for facilitating the transportation vessels,
equipment to move the wind farm components and skilled labour force, if
secondary fabrication is required. The port will require the necessary space
to lay out a production line to fit the components, have a large volume of
storage space and be able to accommodate deep water draft construction
vessels.
5.23.18 The location of other ports associated with the construction process will be
driven by the location of the chosen manufacturing companies for the various
components associated with the wind farm. Experience from Round 1 and 2
projects indicates that this diversity may be at a global scale.
5.24
Onshore Construction
Construction sequence and timing
5.24.1
Onshore, the construction programme is based on a likely 5 year
programme. The construction sequence and approximate length of each is
shown in Table 5.15 for GWF (termed ‘connection’ in the draft DCO)
infrastructure and in Table 5.16 for the transmission infrastructure.
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Table 5.15 Approximate onshore construction timings for GWF infrastructure
Activity
Duration
Site preparation
9 months
Construction of GWF compound
24 months
Onshore cabling
8 months
Transition bays
4 months
Directional drilling works between
2 months
landfall and transition bays
Site demobilisation
5 months
Table 5.16 Approximate onshore construction timings for transmission infrastructure
5.24.2
Activity
Duration
Site preparation
9 months
Pre-outage works
18 months
Outage works
18 months
Post outage works
2 months
It is estimated that the onshore construction workforce will not exceed 200
personnel during the peak construction period. Onshore working shifts are
anticipated to be 08:00 to 19:00 from Monday to Friday; and 09:00 to 13:00
on Saturday. Construction activity may occasionally require 7 days per
week. Where the working hours are expected to extend beyond those given
above, these periods would be agreed in advance with the Local Planning
Authority. The following activities could result in an extended working week:
 Continuous concrete pours, which would generally occur nearer
the start of the civil construction phase
 Weather window during a spate of bad weather
 Testing of equipment.
5.24.3
It is noted that the above work timing does not apply to works related to cable
landfall in the intertidal zone, where working hours will be dictated to a large
extent by the tidal state.
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Site preparation and earthworks
5.24.4
The site boundary will be securely fenced using a suitable steel mesh and
panel fencing system. A construction compound will be located within the
site boundary. This will include contractor’s offices / cabins and an
equipment storage area.
5.24.5
Earthworks will be required in order to create a level area upon which the
substation will be built, which will generate spoil. Excavated material will be
used as part of the site landscaping wherever possible, however this may not
account for all the material generated. Should additional spoil be taken off
site this will be done in accordance with the agreed site waste management
plan.
5.24.6
It is estimated that this phase of the civil engineering works will take
approximately 9 months to complete.
Building construction works
5.24.7
The substation buildings will most likely be constructed immediately following
the initial civil engineering works, with an estimated timescale of 24 months.
Earthworks and planting
5.24.8
The remaining programme of topsoil reinstatement and planting works will be
implemented to visually contain the new substation. Full details are provided
in Section 21 Seascape, Landscape and Visual Character.
Traffic and access
5.24.9
Table 5.17 provides a provisional estimate of the vehicle movements
required during the construction of both the GWF and transmission
compounds and associated infrastructure. This predicts not only the delivery
of major plant items but also the daily travelling of the workforce, based on
current assumptions.
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Table 5.17 Summary of construction related traffic
Key traffic
Site preparation
1315 lorries (2630 movements)
GWF Substation
Onshore cabling
Transition bays
Directional drilling works
Site demobilisation
200. Therefore assume 150 cars per day
Max daily workforce
(300 movements)
5.25
Commissioning
5.25.1
To ensure that the electrical energy from GWF is delivered to the national
400kV transmission system, three parties must ultimately operate the assets
applied for in the GWF consent. Those three parties are GWF, NGET (the
operators of the 400kV network), and the offshore transmission owner
(OFTO) which is the new regulatory regime for licensing offshore electricity
transmission.
5.25.2
The GWF project, as described within this Chapter, can be split into the
following systems or components (listed from onshore connection to wind
far,), from which follows a description of the commissioning process and
associated parties responsible:
 Transmission grid connection (including sealing end compounds);
 Onshore GWF substation;
 Export cables;
 Offshore platform substation;
 OFTO Supervisory Control And Data Acquisition (SCADA) system;
 Array cables;
 Equipment within transition pieces (if TPs are installed);
 Balance of Plant SCADA system;
 Wind Turbine Generators; and
 Wind SCADA system.
5.25.3
NGET will be responsible for the transmission grid connection
commissioning, whilst the OFTO will take responsibility for the onshore GWF
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substation, export cables, offshore platform substations and the associated
OFTO SCADA system.
5.25.4
The GWF project principal contractor will manage the delivery of the
commissioning programme associated with the array cables, equipment
within the transition pieces (if TPs are installed) and the Balance of Plant
SCADA system.
5.25.5
The array cables transport the electrical energy onto the offshore platform
substations, were an assortment of MV equipment manages the electricity
prior to it reaching the OFTO interface point. The GWF project principal
contractor will also be responsible for the commissioning of this MV
equipment. This leaves the GWF WTG and the wind SCADA system to be
commissioned by the appointed wind turbine manufacture.
5.25.6
Commissioning will generally comprise
procedures formalising the different stages:
the
following
process,
with
 A mechanical, visual and electrical continuity assessment;
 An energisation programme;
 Testing mechanical, electrical and control functions;
 Identification of faults;
 Rectification of faults;
 Re-testing; and
 Certification.
5.25.7
The commissioning of GWF will be in accordance with approved
commissioning procedures and would include the NGET commissioning
procedures where applicable. All commissioning activities will be the subject
of an approved safe system of work. Commissioning activities will include
the WTG’s performance and reliability testing and compliance with the grid
code standard.
5.26
Offshore Operations and Maintenance
Overview
5.26.1
All elements of the onshore and offshore GWF project will be designed to
operate unmanned with the systems monitored and instructions issued from
a central location 24 hours a day.
5.26.2
The wind farm and associated plant and apparatus will be controlled and
monitored centrally using SCADA systems, most likely located within the TP.
The SCADA systems are the means by which monitoring is undertaken and
commands relayed to the equipment.
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5.26.3
The facility will also exist for the starting and stopping of WTGs in events
such as emergencies or access to the turbines by helicopter for hoisting
personnel onboard.
5.26.4
The WTG would normally shut down during severe weather conditions, when
wind speeds exceed 25ms-1, to avoid damage to the turbine components.
5.26.5
Planned outages for a WTG will also be triggered primarily by routine
maintenance requirements, but also occasionally at the request of the
Maritime Rescue Co-ordination Centre (MRCC) in support of Search and
Rescue (SAR) activities in the area.
Operational safety zones
5.26.6
It is likely, although to be confirmed, that an operational safety zone of 50m
around each structure will be applied for. Furthermore, during maintenance
operations this will be extended to 500m (the maximum permissible under
international law) around the relevant structures.
5.26.7
The control mechanisms and processes associated with the operational
phase would be as specified under construction details.
5.26.8
Once the Wind Farm is operational, an Automatic Identification System (AIS)
as well as CCTV from the control centre may be used to monitor vessel
movements within the wind farm.
WTG navigation aids and lighting
5.26.9
As with the construction phase, the marking of the wind farm will be in
accordance with the requirements set out in the IALA Recommendation O117 on ‘The Marking of Offshore Wind Farms’ and IALA Recommendation O114 on the marking of offshore structures. Under these recommendations
the following would be of relevance for GWF:
 Navigation aids will be fitted on any WTG below the lowest point of the
arc of rotation of the turbine blades, and at a height above HAT of not
less than 6m or more than 15m, typically at the top of the yellow
section of the mast.
 Corner or significant boundary point WTGs will be designated a
Significant Peripheral Structure (SPS), with a minimum separation
distance of 3nm between SPS’s. Each SPS will be fitted with lights
that are visible from all directions in the horizontal plane, and the lights
on a structure should be synchronised to show a yellow ‘special mark’
light characteristic with a range of not less than 5 nautical miles.
 Intermediate Peripheral Structures (IPS) may be used between SPS.
These will be within 2nm of SPS, and fitted with lights as per SPS, but
with a distinct flash characteristic. They will be visible from a minimum
range of 2nm.
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5.26.10 Additional aids to navigation will be at the discretion of the operator, and may
include:
 Racons, which may have morse letter ‘U’ or radar reflectors;
 AIS; and
 Sound signals may be fitted for restricted visibility with a range of not
less than 2 nautical miles.
5.26.11 Ancillary structures will be marked in accordance with IALA Recommendation
O-114 on the Marking of Offshore Structures.
5.26.12 Individual WTG will be marked with a unique alphanumeric identifier which
will be clearly visible at a range of not less than 150m. At night, the identifier
will be lit discretely (e.g. with down lighters).
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Operation and maintenance activities
5.26.13 O&M of the wind farm after commissioning will comprise both scheduled and
unscheduled maintenance events. Scheduled works on the WTG and
onshore/offshore electrical infrastructure will include annual or bi-annual
maintenance and inspection visits. In addition, necessary retrofitting and
upgrading works may also take place. The scheduled works will normally be
timetabled for the summer months, given the typically more settled weather
and longer day light hours. During this period, O&M personnel at site will be
expected to peak, consisting of up to 30 technicians and eight vessel crew
aboard four vessels.
5.26.14 Unscheduled repair activities will range from attendance on location to deal
with the resetting of false alarms through to major repairs. The frequency of
unscheduled activities is expected to be highest in the early years of
operation (one visit per turbine, per month) when experience on other wind
farms sites has shown the highest number of teething faults tend to occur.
After the first two years of operation, unscheduled visits to turbines are
expected to reduce in frequency to six month intervals.
Access strategy
5.26.15 Access to each installation offshore will be by boat or helicopter with at least
two service personnel being on each offshore structure at any one time for
safety reasons. In order to achieve the maintenance programme, it is
anticipated that O&M teams will work simultaneously on several WTG (and
potentially also on the offshore substations). It is therefore expected that,
when boat access is required, at least two vessels will be on-station within
the wind farm site at all times that O&M work is being undertaken.
5.26.16 GWFL will consider the use of both boats (GGOWF is currently using
aluminium catamarans known as windcats) and helicopters when
establishing a suitable access strategy. The boats may be used for routine
maintenance operations and in weather conditions up to approximately 2m
wave height. Helicopters may be used in situations which are time critical
and for facilitating access when vessels are unable to work.
5.26.17 GWFL may also explore the requirement for a mothership, which would serve
to accommodate personnel, provide a control room facility and act as the
main stores location for the site. Such vessels are also commonly fitted out
with a number of work boats and associated launch and recovery systems.
Latest mothership vessel designs also incorporate ROV, diver operations and
helicopter pads and are therefore able to service much of the post
construction and asset management work that would be required over the life
of the project.
5.26.18 The primary means of transferring personnel will be via the workboats which
may be stationed with the mothership (if utilised), but this approach will also
be supplemented by helicopter support.
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5.26.19 Detailed evaluation is underway to identify the best access strategy for GWF.
The includes the potential to extend existing GGOWL services to cover the
GWF project.
Maintenance team
5.26.20 GGOWF already have an Operational Team in place for the day to day
management and control of that project. The GGOWF Operational Team are
based in a purpose-built facility situated on the quay side at Lowestoft. This
is also the location of the maintenance transportation vessel. The operation
and maintenance activities have already been scoped, plans developed and
necessary services procured. In addition, call-off orders are already in place
with companies who can provide specialist vessels or equipment that might
be required at short notice in the event of a failure.
5.26.21 Further investigation is presently being undertaken to assess the suitability of
the GGOWF work remit and services being extended to include the GWF
project as it enters its working phase.
5.26.22 The OFTO will be responsible for the offshore substations and the export
cables. Once appointed it will be their decision on the exact numbers of full
time service personnel, the marine access options to be used and their base
location.
Offshore accommodation
5.26.23 The addition of an accommodation platform could facilitate the mobilisation of
maintenance crew for short durations or in an emergency, adding a degree of
further flexibility to the maintenance strategy. Further detailed analysis will
be undertaken to evaluate the benefits of an accommodation platform before
any decision is taken on whether to use one. GWFL would explore all
possible accommodation options, if required, including a fixed platform,
floating hotel and jack-up vessel for transferring and accommodating
maintenance staff.
5.26.24 The supply logistics for whichever offshore accommodation option is selected
will be managed by the onshore O&M base, with an offshore supply vessel
used to replenish the accommodation facility with food, water (if necessary),
fuel, spares and equipment on a regular basis to meet operational
requirements.
Operation and maintenance port and facilities
5.26.25 The GGOWF project has utilised Lowestoft, in Norfolk, and it is noted that
this facility has additional space which could be converted to accommodate
GWF. However as for construction, the O&M port is under consideration and
is the subject of an independent port feasibility study.
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5.26.26 The O&M base will need to be able to provide facilities for the O&M crew,
control centre for operations, storage space for maintenance equipment and
spare parts, and some strategic spare parts such as gearboxes, generators,
and possibly blades.
5.26.27 It is also likely that a telecommunication mast will have to be erected as part
of the O&M base infrastructure to communicate with the wind farm personnel
and associated transport. Typically the mast will be approximately 18m high
and be used for VHF telecommunications and microwave line of site
communications if used.
5.26.28 The chosen O&M facility will be equipped with a chart indicating the position
of the GWF WTGs and displaying their unique identification numbers, in
accordance with MGN 371 (M+F).
5.26.29 It will be possible for each individual WTG to be remotely controlled from the
O&M facility. This would enable WTG to be controlled and shut down at the
request of the MRCC in support of SAR activities in the area. These
procedures will be tested on a regular basis, in accordance with MGN 371
(M+F). Furthermore, the WTG will be remotely monitored on a 24 hour basis
from the WTG manufacturer’s control room. The above is discussed in more
detail in Chapter 16, Shipping and Navigation. Any port works falling
under the remit of the Planning Act, the Town and Country Planning Act or
other relevant planning legislation do not form part of the GWF application.
5.27
Onshore Operations and Maintenance
Cable route overview
Operation
5.27.1
Once operational the onshore cable system will primarily be beneath the
ground surface and buried to a sufficient depth to allow ploughing and other
agricultural practices to continue. The only above ground features will be
related to the onshore transition bays and, if implemented, joint boxes along
the cable route.
Maintenance
5.27.2
A full check of the cable system will be carried out on an annual basis.
Access will normally be along the implemented cable route by foot.
Fault repairs
5.27.3
In the unlikely event that there is any failure of cables, a fault finder with test
gear will locate the fault along the cable section. Once located, the area
around the fault will be excavated and the fault repaired. If the cable cannot
be repaired, a new length of cable will be inserted and jointed to replace the
failed section.
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Substation overview
Operation and maintenance
5.27.4
It is not anticipated that the new substation will be permanently manned but
maintenance and inspection visits would occur.
5.27.5
In summary, the main equipment at the site will consist of transformers,
electrical reactors, capacitors, and switchgear. Best practice guidelines for
the frequency of maintenance of this equipment is summarised in Table 5.18
and would be adhered to during the lifetime of the operational phase.
Table 5.18
Maintenance required at substation
Equipment
Maintenance
frequency
Type of work
Transformer /
electrical reactor
Routine – annually

Check silica gel and ventilator,
check for oil leakage, check cooling
equipment, general visual
inspection;

Test for water content, dielectric
strength, acidity and dissolved gas
analysis; and

Clean bushings and grease
ventilator.
Intermediate – four
years
Major – 12 years
Capacitors

General visual inspection.
GIS / AIS switchgear

Check gas pressure, check and
clean mechanisms and hydraulics;
and

Test protection and control
equipment.
Intermediate – six
years
5.27.6
It is envisaged that the maintenance works will normally only require a site
visit by a light goods vehicle (LGV).
Any major equipment failure
necessitating removal will require the use of suitable mobile cranes.
Utilities and environmental issues
5.27.7
Potable water for drinking and washing will be provided by a permanent
connection to the local mains water network. Wastewater disposal from site
will via onsite capture, e.g. septic tank.
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5.27.8
Surface water drainage options will be developed based on an understanding
of the area of impermeable surfaces being created and known soil infiltration
rates. Proposals for surface water drainage are contained in the Flood Risk
Assessment to this application. Surface water quality will be protected from
pollution sources by the following measures:
 Oil retention bunds around (and in some cases below) the
transformers, reactors and any other oil filled equipment that
may be used; and
 Oil interceptors on the surface water drainage gullies.
5.27.9
The transformers and electrical reactors will be filled with mineral insulating
oil and will be located within bunds (with underground voids for emergency
discharge) to contain any leakage. The capacitors are sealed units and
contain non-PCB, biodegradable insulation liquid. The switchgear will be
constantly monitored for gas pressure to detect any leakage.
5.27.10 Transformers, electrical reactors and associated cooling equipment will
comply with NGET noise level specifications measured in accordance with
IEC 60076-10. Noise impacts are considered within Chapter 26 Noise.
5.27.11 It is not envisaged that the site will be provided with permanent lighting
around the internal roads or equipment. Lighting may be provided at the
main entrance doors for safe ingress / egress to the buildings. In the event of
any essential works, temporary task lighting may be provided by the
maintenance staff in addition to any installed lighting use.
Operational safety zones
5.27.12 The onshore substation site will have a security fence surrounding its
perimeter. Beyond this there are no formal operational safety zones
envisaged for GWFL.
5.28
Repowering
5.28.1
The wind farm’s operational life is defined (by The Crown Estate) as up to 25
years; an additional two years will be granted to the lease to allow
decommissioning to take place. All elements of the wind farm will be
designed with a minimum operational life of 25 years.
5.28.2
Following this a decision will be made on whether the operating company
wish to proceed with decommissioning or apply to the relevant Regulatory
Authority at the time, to repower the wind farm.
5.28.3
Should repowering be sought then an investigation would be undertaken as
to the possible options for this. It is envisaged that any such repowering
activity will require a new agreement for lease with The Crown Estate and
would be subject to an additional planning consent application.
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5.28.4
It is acknowledged within the Scoping Opinion for GWF that the statutory
nature advisory body (the Joint Nature Conservation Committee, JNCC) has
requested (on page 5 of their response) that:
“It is important to be clear on what repowering entails and whether there
is likely to be any relocation of subsea infrastructure or alteration of the wind
farm layout. This includes whether further scour protection is required for
foundations in the same, or in new, locations across the wind farm site. Any
alterations to the locations of offshore elements for repowering may require
an update to the benthic survey work and assessments that have previously
been carried out”.
5.28.5
GWFL are not able to make such detailed statements with regard to
repowering at this stage. However GWFL do commit to working closely with
the Government’s advisory bodies throughout the life cycle of the project and,
should at any stage repowering be considered, progressing detailed dialogue
covering how such matters would take place. As such, repowering would be
subject to a separate consents application process and is not considered
further within the current application and EIA process.
5.29
Decommissioning
5.29.1
The requirement to decommission is a condition of The Crown Estate lease
and is also incorporated in the statutory consenting process through the
provisions of the Energy Act 2004. Under the statutory process, GWFL is
required to prepare and review a detailed decommissioning plan at the
request of the Secretary of State and set aside funds for the purposes of
decommissioning in accordance with BERR’s Guidance Note for
‘Decommissioning Offshore Renewable Energy Installations under the
Energy Act 2004’.
5.29.2
The decommissioning plan will consider the latest technological
developments, legislation and environmental requirements at the time that
the work is due to be carried out.
5.29.3
For the purposes of the current consenting framework and as a basis for the
GWF EIA, an outline decommissioning programme based on the current
technological and regulatory framework is provided in the following
paragraphs.
Decommissioning of offshore components
Decommissioning of Turbines
5.29.4
The removal of the superstructure is expected to involve the approximate
reverse of the installation procedure:
 Conduct
assessment
on
potential
hazards
during
the
decommissioning work and pollutants to the environment that may
result from the decommissioning work;
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 Disconnect turbine from electrical distribution and SCADA;
 Mobilise suitable vessels to the site;
 Remove any potentially polluting or hazardous fluids/materials from
the turbine (if identified in the risk assessment);
 Remove rotor blades;
 Remove nacelle;
 Remove tower sections; and
 Transport all components to an onshore site, where they will be
processed for reuse/recycling/disposal.
Decommissioning of offshore platform topsides
5.29.5
The methodology for removal of the offshore platform topsides is likely to be
as follows:
 Conduct
assessment
on
potential
hazards
during
the
decommissioning work and pollutants to the environment that may
result from the decommissioning work;
 Isolate/disconnect from the grid and SCADA;
 Remove any potentially polluting or hazardous fluids/materials (if
identified in the risk assessment);
 Mobilise suitable heavy lift vessel to the site;
 Remove main topside structure; and
 Transport to an onshore site, where it will be processed for
reuse/recycling/disposal.
Decommissioning of offshore foundations
5.29.6
It is currently envisaged that piled foundations will be cut below seabed level
(using methods such as abrasive water jet cutter or abrasive diamond wire
cutting) with the protruding section being removed. Removing the whole pile
is expected to be neither practical nor desirable. The use of explosives in
removing the piles completely is discounted due to the likely damage it may
cause to the environment.
5.29.7
It may be preferable to leave gravity base structures on the seabed to
preserve the marine habitat that has established over their life, subject to
discussions with key stakeholders and depending on the regulations in place
at the time. In this case the central tubular column would be cut off and
removed whilst the base would remain in place.
5.29.8
Suction can and suction monopod structures are likely to be lifted and
removed using a heavy lift vessel.
Final Report
9V3083/R01/303424/Exet
November 2011
Removal of scour protection
5.29.9
It may be preferable to leave any scour protection around the turbine bases
or covering cables in-situ in order to preserve the marine habitat that has
been established over the life of the wind farm (again subject to discussions
with key stakeholders). However, if it is considered preferable to remove
scour protection this could be achieved using the following techniques:
 Dredging of the scour protection with subsequent disposal at an
approved offshore spoil location or transportation to an approved
onshore site for recycling or disposal as appropriate; and
 For rock fill, the individual boulders may be recovered using a grab
vessel, deposited in a hopper barge, and transported to an approved
site for recycling or disposal as appropriate.
Removal of offshore cabling
5.29.10 Discussions will be held with stakeholders and regulators to determine the
exact locations where offshore cables are required to be left. Cables will be
left in situ if considered appropriate, or wholly or partially removed.
Throughout the project life-cycle, the burial depth will be closely monitored. In
the vicinity of the cable crossings, cables are likely to remain in place to avoid
unnecessary risk to the integrity of the cables. A typical cable removal
programme will include the following:
 Identify the location where cable removal is required;
 Removal of cables: Feasible methods include pulling the cable out of
the seabed using a grapnel, pulling an under-runner using a steel
cable to push the electrical cable from the seabed, or jetting the
seabed material.
 Transport cables to an onshore site where they will be processed for
reuse/recycling/disposal.
Final Report
9V3083/R01/303424/Exet
November 2011
Decommissioning of onshore components
5.29.11 The application includes an Onshore Decommissioning Statement, which
provides a basis for subsequent approval (under the DCO) for
decommissioning proposals to be agreed with the relevant planning authority.
The following sections are based on the content of the above Statement.
5.29.12 It is intended that the majority of cables, ducts and underground services will
be left in situ, although main electrical cables may be removed from their
ducts (but with the ducts remaining in situ. This will minimise disturbance to
existing land uses established above the cable corridors.
5.29.13 All above surface equipment and structures associated with the transition
bays will be removed from site and concrete foundations removed to a depth
of 1m and any subsurface chambers removed.
5.29.14 In the onshore substation all above surface equipment and structures will be
removed from the site. Concrete foundations and chippings will be removed
to a depth of 1m and subsurface tanks and chambers will be removed. The
site will then be restored through natural regeneration (with a potentially very
limited extent of planting).
5.29.15 The landform and associated planting would be left in situ, however there
may be some minor breaking up of the internal face of the landform, subject
to geotechnical safety considerations.
5.29.16 All above surface non-operational equipment and structures in the sealing
end compounds will be removed from the site. Concrete foundations and
chippings will be removed to a depth of 1m and the sites restored to an
appropriate habitat type to be agreed with SCDC. The replacement tower
arms will be left in place.
Final Report
9V3083/R01/303424/Exet
November 2011
5.30
References
DONG energy, (2009). The Monopod Bucket Foundation; Recent experience
and challenges ahead. Presentation at Offshore Wind 2009
DOWL, (2009). Dudgeon Offshore Wind Farm: Environmental Statement.
DOWEC, (2003). Suction bucket foundation. Feasibility and pre-design for
the 6 MW DOWEC
GGOWL, (2009). Cable laying and landfall plan
GGOWL, (2011). Greater Gabbard Construction Method Statement
Ibsen, L.B., Liingaard. M., Nielsen, S. A, (2005). Bucket Foundation, a status.
Jim Hodder Associates. (2010). Galloper Wind Farm: Cable Desktop Study.
Report C1001\101130
Subacoustech, (2011). Underwater noise modelling for the Galloper Wind
Farm
Nedwell J R, Turnpenny A W H, Lovell J, Langworthy J W, Howell Dm and
Edwards B. (2003). The effects of underwater noise from coastal piling on
salmon (Salmo salar) and brown trout (Salmo trutta). Subacoustech report to
the Environment Agency
Nedwell J R, Parvin S J, Edwards B, Workman R, Brooker A G and Kynoch J
E (2007) Measurement and interpretation of underwater noise during
construction and operation of offshore windfarms in UK waters.
Subacoustech Report No. 544R0738 to COWRIE Ltd
Parvin S J and Nedwell J R. (2006). Underwater noise survey during impact
piling to construct the Barrow Offshore Wind Farm. COWRIE Project ACO04-2002
The Crown Estate, (2010). A guide to an Offshore Wind Farm.
Final Report
9V3083/R01/303424/Exet
November 2011

ES Chapter 5 - Galloper Wind Farm

Transcription

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