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Galloper Wind Farm ProjectEnvironmental Statement – Chapter 5: Project Details

November 2011Document Reference – 5.2.5

Galloper Wind Farm Limited

Galloper Wind Farm ES - i - 9V3083/R01/303424/Exet

Final Report November 2011

Document title Galloper Wind Farm Project

Environmental Statement – Chapter 5: Project Details

Document short title Galloper Wind Farm ES

Document Reference 5.2.5

Regulation Reference APFP Regulations 5(2)(a)

Version 14

Status Final Report

Date November 2011

Project name Galloper Wind Farm Project

Client Galloper Wind Farm Limited

Reference 9V3083/R01/303424/Exet

Drafted by GWFL & Royal Haskoning

Checked by Various

Date/initials check RS PT 30.05.2011

GWFL Approved by Kate Harvey

Date/initials approval KH 18.11.2011

Galloper Wind Farm ES 9V3083/R01/303424/Exet

Final Report - iii - November 2011

CONTENTS Page

5 PROJECT DETAILS 4 5.1 Introduction 7 5.2 Outline Project Description 7 5.3 Site Location 8 5.4 Wind Resource 11 5.5 Offshore Physical Characteristics 12 5.6 Wind Farm Flexibility and Layout 13 5.7 Wind Turbine Generators 21 5.8 WTG Support Structures 28 5.9 WTG Support Structure Ancillary Equipment 31 5.10 WTG Foundation Systems 33 5.11 Ancillary Infrastructure 65 5.12 Inter, Intra-array and Export Cables 70 5.13 Cable Landfall 83 5.14 Landfall and Other Onshore Drilling Works 86 5.15 Onshore Transition Bays 90 5.16 Onshore Cabling 91 5.17 Onshore Substation 96 5.18 Landform 107 5.19 Sealing end compounds, gantries and overhead wires 109 5.20 Other onshore infrastructure 111 5.21 Summary of onshore infrastructure permanent and

temporary footprint 113 5.22 Project Programme 115 5.23 Offshore Pre-construction and Construction 116 5.24 Onshore Construction 120 5.25 Commissioning 123 5.26 Offshore Operations and Maintenance 124 5.27 Onshore Operations and Maintenance 129 5.28 Repowering 131 5.29 Decommissioning 132 5.30 References 136


Final Report Chapter 5 - November 2011

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



Service corridors, including telecommunications, water and connection to the local electricity network.

5.1.2 Plot 5.1 on the following page shows the high level components of GWF.



Plot 5.1 Galloper Wind Farm overview


Final Report Chapter 5 -

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.



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).



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



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 intra-array 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



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:



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.



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 post-consent.

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



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;



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.



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)



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 pre-installed 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.



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).



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

MHWS

22m 22m 22m

Maximum number of WTG

likely in wind farm (based

on typical nameplate

capacity)

140 140 84*

Hub height (ma LAT) 79.5m 86m 120m

Maximum tip height (ma

LAT)

133.1m 146m 195m**



WTG detail 107m rotor 120m rotor 164m rotor

Rotor diameter 107m 120m 164m

Cut in/out speed 3-5ms-1 cut in,

25ms-1 cut out

3-5ms-1 cut in,

25ms-1 cut out

3-5ms-1 cut in,

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

area

1.264km2 1.583km2 1.521km2

Typical expected

‘nameplate’ MW rating for

this order of rotor

diameter (for assisting

comprehension in relation

to the total 504MW

capacity only)

3 - 3.6MW 3.6 - 4MW 6 - 7MW

* 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.”.



Table DCO.1 Section: WTG parameters Ref DCO constraint

wording Key flexibility arising within DCO constraint

Comment

Sch1, Pt 1, (1)(a)

An offshore wind turbine

generating station with a

gross electrical output

capacity of up to

504MW comprising up

to 140 wind turbine

generators

Any capacity below

504MW or number below

140 turbines is permitted,

regardless of turbine size

A minimum Requirement

would be unenforceable.

In practice most UK wind

farms have been built out

to their full MW capacity

Any ‘nameplate’ MW

capacity of turbine is

permitted

Capacity is a function of

rotor diameters within

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

generator forming part

of the authorised

development shall:

exceed a height of 195

metres when measured

from LAT to the tip of

the vertical blade

All maximum tip heights

below 195m are

permitted, including below

135m

Whilst permitting a blade

tip below the minimum

135m considered in the

assessments, a minimum

is achieved by a

combination of the

minimum blade diameter

and minimum clearance.

Sch1, Pt 3, (3)(b)

No wind turbine


of the authorised

development shall:

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

Hub height may be at any

height at or below 120m

In reality the minimum hub

height is fixed by a

combination of minimum

blade diameter and

minimum clearance



Sch1, Pt 3, (3)(c)

No wind turbine


of the authorised

development shall:

exceed a rotor diameter

of 164 metres, or have a

rotor diameter of less

than 107 metres

Any rotor diameter at or

between 107m and 164m

is permitted

Multiple turbine types may

be used in the

development

In practice, more than two

turbine types is unlikely for

commercial reasons

Sch1, Pt 3, (3)(d)

No wind turbine


of the authorised

development shall:

be less than 642 metres

from the nearest WTG

in either direction

perpendicular to the

approximate prevailing

wind direction or be less

than 856 metres from

the nearest WTG in

either direction which is

in line with the

approximate prevailing

wind direction

Irregular layout across the

entire offshore

development area, or any

part thereof, is possible

Where turbines are built, a

reasonably regular layout

is likely in practice, though

a perfect pattern of rows is

unlikely in any one area

Large parts of the

development area may

not be used at all

No limit on how many

turbines can be placed in

each array area, as long

as minimum separation

distances are maintained

No minimum separation

distance is imposed

between turbines and

other structures

The prevailing wind

direction is not defined,

allowing the minimum

distance of 642 metres

from the nearest WTG to

be applied in any desired

direction

The prevailing wind

direction is unlikely to vary

significantly from that

shown in this Chapter

based on existing

measurements and

inevitably promoters will

seek the largest spacing

in the prevailing wind

direction



Any minimum blade tip

separation distance

above MHWS greater

than 22m is permitted

The minimum distance is

sought by promoters since

this distance has been

agreed with the Royal

Yachting Association

(RYA) for all offshore wind

farms.

Sch1, Pt 3, (3)(e)

No wind turbine


of the authorised

development shall:

have a distance of less

than 22 metres between

the lowest point of the

rotating blade of the

wind turbine and MHWS

Any clearance above 22m

is permitted, although in

reality turbines seek to

minimise clearance to

reduce increases in tower

height and foundation

loads

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.



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.

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.

Plate 5.3 Typical monopile transitional piece

Source: www.kentishflats.com



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;



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. J-tubes 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



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



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.



Table DCO.2 Section: Foundation types Ref DCO constraint wording Key flexibility arising

within DCO constraint Comment

Sch1, Pt 1, 1(a)

Wind turbine generators

each fixed to the seabed

by one of four foundation

types (namely, monopile

foundation, space frame

foundation, suction

monopod foundation or

gravity base foundation)

Use of any mix of

foundation types in any

array area. Particular types

may be dispersed

throughout or concentrated

within specific areas

In practice, no more than

one or two foundation types

are likely to be used for

commercial reasons and for

consistency.

Ability to use different sizes

and detailed design of

foundation within the four

defined types

The ‘worst case’ is defined

by additional DCO

constraints for each defined

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.



Plate 5.5 Indicative monopile foundation

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).

Intermediate platform

External J tubes

Boat landing / ladder

Work platform

Grouted connection

Scour protection (if required)

Transition piece

Monopile

Turbine tower



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.



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.



Table DCO.3 Section: Monopile foundation Ref DCO constraint wording Key flexibility arising


Sch1, Pt 3, 7(1)

Each monopile foundation

forming part of the

authorised development

shall not have a diameter

greater than 7 metres

Monopiles could be utilised at all diameters below 7m.

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

Monopiles of varying diameter could be used within the development

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

Any mix of monopile sizes could be used within all array areas

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 of any length or embedment below the seabed could be used

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.

Sch1, Pt 3, 7(2)

Each monopile foundation

forming part of the


shall not be constructed in

water with a depth greater

than 45 metres between

LAT and the seabed.

Monopiles may be used anywhere where the depth from LAT is less than 45m

Ref Constraint to be applied by deemed Marine Licence Comment Sch 6, Pt 2,

Number of piling operations and location at any one time 9(c) of the Marine Licence requires a construction



9(c) method statement to be approved by the MMO before licensed activities commence

Sch 6, Pt 2, 12

Timing of piling operations 12(1) and (2) of the Marine Licence impose a seasonal restriction unless otherwise agreed

Ref Constraint to be applied by other regimes

Comment

The ‘Habitats Regulations’ & the ‘Offshore Marine Regulations”

Number of piling operations and location at any one time

Controlled through an EPS License application to the MMO



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

Shaft

Intermediate Platform

Work Platform

Boat Landing / Ladder

Internal J-tube &

Ballast

Scour Protection

Under-base Grout

Skirt



Plate 5.9 Indicative column GBS foundation


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 post-consent.

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.

Scour protection

Skirt

Turbine

Tower

Under-base

grout

Boat Landing

Intermediate

Platform

Shaft

External J-tubes

Work

Platform



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



Table DCO.4

Section: Gravity base foundation Ref DCO constraint wording Key flexibility arising


Sch1, Pt 3, 7(3)(a)

Each gravity base foundation forming part of the authorised development shall not have: a diameter at the level of the seabed which is greater than 45 metres

Gravity bases could be used at any seabed diameter below 45m

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

Sch1, Pt 3, 7(3)(b)

Each gravity base foundation forming part of the authorised development shall not have: a base height, where there is a flat base, which is greater than 7.5 metres above the level of the seabed

Any base height below 7.5m would be permitted.

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.

Sch1, Pt 3, 7(3)(c)

Each gravity base foundation forming part of the authorised development shall not have: a column diameter, where there is a flat or conical base, of greater than 10 metres

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.

Sch1, Pt 3, 7(3)(d)

Each gravity base foundation forming part of the authorised development shall not have: a cone/column intersect which is higher than 20 metres above the top of the base

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



Sch1, Pt 3, 7(3)(e)

Each gravity base foundation forming part of the authorised development shall not have: a cone diameter at its base which is greater than 35 metres

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)

Sch1, Pt 3, 7(4)

In the event that any WTG uses a gravity base foundation of more than 35 metres diameter at the level of the seabed, the authorised development shall not comprise more than 101 WTG in total

Any mix of base sizes may be used up to 140 number WTG, except where there is a base above 35m diameter, in which case only 101 WTG bases may be used

In reality, base sizes are likely to be consistent across large areas of the site

Ref Constraint to be applied by deemed Marine Licence Comment Sch 6, Pt 2, 9 (b)

Exact detailed design of foundations and locations 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 pre-



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.



Plate 5.11 Indicative four-legged space-frame lattice substructure

Pile



Plate 5.12 Indicative suction can support to a three legged space-frame substructure


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 space-frame foundation.

Suction can



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 space-frame 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.



Table DCO.5

Section: Space-frame foundation Ref DCO constraint wording Key flexibility arising


Sch1, Pt 3, 7(5)(a)

Each space frame

foundation forming part of

the authorised

development shall not

have:

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

All leg spacings below 40m

at the seabed and 25m at

LAT are permitted

In reality the reduction in

spacing will reach a

practical minima where the

foundation can no longer

resist the overturning

moment from the turbine

Sch1, Pt 3, 7(5)(b)

Each space frame


the authorised


have:

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

All leg spacings below 40m

at the seabed and 25m at

LAT are permitted

In reality the reduction in

spacing will reach a

practical minima where the

foundation can no longer

resist the loads from

structure above



Sch1, Pt 3, 7(5)(c)

Each space frame


the authorised


have:

more than two piles per

leg or more than one

suction can per leg

In combination with (i),

permits up to 8 piles/4

suction cans per WTG

foundation, and 12 piles/6

suction cans per offshore

platform

Sch1, Pt 3, 7(5)(d)

Each space frame


the authorised


have:

a pile diameter which is

more than 3 metres each

Individual piles can be any

size at or below 3m

diameter with any mix of

pile sizes on a single

foundation and pile designs

are not uniform across the

site

Whilst possible to change

pile sizes on an individual

foundation, piles to date

have ordinarily been utilised

in a uniform manner for

offshore wind farm

foundations, both

individually and across

arrays

Sch1, Pt 3, 7(5)(e)

Each space frame


the authorised


have:


meteorology mast, a

suction can diameter

greater than 11.5m each,

where the total number of

suction cans per structure

is 3 or less

Permits any diameter up to

11.5 metres when there are

3 or less suction cans for a

WTG or met mast

structure.

Sch1, Pt 3, 7(5)(f)

Each space frame


the authorised


have:


meteorology mast, a

Permits any diameter up to

10 metres when there are

up to 4 suction cans for a

WTG structure or met mast

(in combination with (i)).



suction can diameter of

greater than 10m each,


suction cans is more than

3

Sch1, Pt 3, 7(5)(g)

Each space frame


the authorised


have:





suction can of greater

than 17 metres each,


suction cans is 4 or less

Permits any diameter of up

to 17 metres when there

are 4 or less suction cans

for an offshore platform.

Sch1, Pt 3, 7(5)(h)

Each space frame


the authorised


have:





suction can or greater

than 10 metres each,


suction cans is more than

4

Permits any diameter of up

to 10 metres when there

are more than 4 suction

cans for an offshore

platform.

Sch1, Pt 3, 7(5)(i)

Each space frame


the authorised


have:

(i) permits any number of

legs at or below 4 for a

WTG or met mast structure

or 6 for a platform.

All space-frame foundations

used in the industry to date

have been 4 or 3 legged. 2

legs do not provide

sufficient lateral stability. 6



more than 4 legs for a

WTG or meteorology

mast, or more than 6 legs

for an offshore substation

platform, accommodation

platform or collection

platform

legs are only likely on larger

offshore platforms.

Ref Constraint to be applied by deemed Marine Licence Comment

Sch 6, Pt 2, 9(b)

Exact detailed design of foundations and locations 9(b) of the Marine Licence

requires submission of a

scheme setting out details

including the number,

dimensions and type of all

foundations

Sch 6, Pt 2, 12

Timing of piling operations 12(1) and (2) of the Marine Licence impose a seasonal restriction unless otherwise agreed

Ref Constraint to be applied by other

regimes

Comment

The ‘Habitats Regulations’

& the ‘Offshore Marine

Regulations”

Number of piling operations and

location at any one time

Controlled through an EPS

License application to the

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).



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.



Table DCO.6

Section: Suction monopod foundation Ref DCO constraint wording Key flexibility arising

within DCO constraint

Comment

Sch1, Pt 3, 7(6)(a)

Each suction monopod


the authorised


have:

a diameter at the level of

the seabed which is

greater than 25 metres

All base diameters at or

below 25m are permitted

Any mix of base diameters

is permitted within the

development

Sch1, Pt 3, 7(6)(b)



the authorised


have:

a base height, where

there is a flat base, which

is greater than 7.5 metres

above the level of the

seabed

Any height below 7.5m

above the seabed is

permitted

Any mix of heights above

seabed level is permitted

within the development

Sch1, Pt 3, 7(6)(c)



the authorised


have:

a column diameter which

is greater than 9 metres

Any column diameter at or

below 9m is permitted

In reality, a column

diameter less than 5m is

unlikely due to the

structural support required

to the turbine above

Any mix of column

diameters is permitted

within the development



Constraint to be applied by deemed Marine Licence Comment

Sch 6, Pt 2, 9(b)






foundations



WTG foundation detail summary

Table 5.2 WTG foundation parameters summary

Foundation detail Monopiles Gravity base systems

Space-frames

Suction monopods

Likely maximum water depth 45m N/A N/A N/A

Maximum diameter at seabed

7m 45m 3m per pin

pile or 11.5m

per suction

can

25m

Maximum number of

turbines**

140 140(≤35m Ø)

101(>35m Ø)

140 140

Maximum column diameter 7m 10m N/A 9m

Maximum number of piles per

WTG foundation

1 None 8 (2 piles per

leg, up to 4

legs)

None

Maximum seabed footprint

(per foundation, excluding

scour)

38.5m2 1,590m2 85m2 (piled)

or 314m2

(suction cans)

491m2

Maximum number of ‘legs’ 1 1 4 1

Maximum penetration depth

below existing seabed level

50m 5m 70m (piled) or

12m (suction

cans)

20m

Maximum volume of grout (per

foundation)

23m3 318m3 212m3 N/A

Maximum volume of arisings

(per foundation)

1,600m3 4,800m3 1,300m3 500m3

** 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.



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 pre-defined 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.



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


Space-frames

Suction monopods

Maximum diameter of

foundation at seabed

7m 45m 3m per pin

pile or 11.5m

per suction

can

25m

Maximum scour protection

(radius beyond the

outermost perimeter of each

foundation/leg base)

20m

10m 5m (piled) or

6m (suction

cans)

10m


area (per foundation,

comprising all legs where

relevant)

1,700m2 1,730m2 1,510m2

(piled) or 962

m2 (suction

cans)

1,100m2


depth (per foundation)

2m 2m 2m 2m


volume (per foundation)

3,400m3 3,460m3 *3,020m3

(piled) or

1,924m3

(suction

cans)

2,200m3

Approximate percentage of

foundations requiring scour

10% 100% 25% (piled)

or 100%

100%




Space-frames

Suction monopods

protection (suction

cans)

Volume of scour protection

for cable entry (for

maximum 140 turbines)

34,300m3 Not required 35,600m3 (no

extra

required for

suction cans)

Not required


volume (cable entry and

foundations for 140 turbines,

except GBS at 101 no.)

82,000m3

349,500m3

(for worst

case 101 x

45m base)

141,300m3

(piled) or

269,360m3

(suction

cans)

308,000m3

* 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.



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



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.



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.



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.



Table DCO. 7 Other foundation parameters Constraint to be applied by deemed Marine

Licence Comment

Sch 6, Pt 2, 9(e)

Extent of scour protection A scour protection

management and cable

armouring plan must be

submitted to the MMO for

approval under the marine

licence



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;



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 space-frame 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

Space-frame (piled)

Space-frame (suction can)

Monopile

Maximum diameter of foundation at seabed 3m per pin

pile

17m 7m

Maximum number of ‘legs’ 6 4 1

Maximum scour protection (radius beyond the

outermost perimeter of each foundation/leg

base)

5m 12m 20m



Foundation detail

Space-frame (piled)

Space-frame (suction can)

Monopile

Maximum scour protection area (per foundation,

comprising all legs where relevant)

2,262m2 4,373m2 1,700m2

Maximum scour protection depth (per

foundation)

2m 2m 2m

Maximum scour protection volume (per

foundation)

4,524m3 8,746m3 3,400m3

Assumed percentage of foundations requiring

scour protection

100% 100% 100%

Volume of scour protection for cable entry (for

maximum 140 turbines)

Included below

Maximum scour protection volume (up to 4

platforms)

18,100m3 35,000m3 13,600m3

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.



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 OSP / Collection station / Accommodation platform

Met-mast

Maximum number

4 (up to 3 no. OSP, 1 no.

Collection, 1 no.

Accommodation)

3

Maximum height (above LAT) 75m 120m

Foundation options

Space-frame and monopile

(as detailed in Table 5.2)

Monopile, GBS, space-

frame and suction monopod

(as detailed in Table 5.2)



Table DCO.8 Section: Other Offshore platform and met mast constraints DCO constraint wording Key flexibility arising


Sch1, Pt3, 5(1)

The total number of

offshore substation

platforms, accommodation

platforms and collection

platforms forming part of

the authorised


exceed four

Any combination of

different platform types is

permitted

Scheme is limited to one


by Work No 1(b) of the

DCO; one collection

platform limited by Work

No 1(c); no more than

three met masts limited by

Work No 1(d).

Sch1, Pt3, 5(2)

The dimensions of any

offshore substation

platform, accommodation

platform or collection

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.

Any clearance to MHWS is

permitted and any size

below those stated is

permitted

Sch1, Pt3, 5(2)

Nor shall it [any offshore


accommodation platform or

collection platform forming

part of the authorised

development] have more

than one supporting

foundation

Work No 1(b) of the DCO

restricts the

accommodation platform to

a monopile or space-frame

type foundation only. Work

No 1(c) restricts the

collection platform to

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 Met masts are permitted to



5(3) shall exceed a height of

120 metres, nor shall it

have more than one

supporting foundation

adopt any height below

and including 120 metres.

Any foundation type is

permitted on met masts

Confirmed by Work 1(d) of

the DCO

Constraint to be applied by deemed Marine Licence Comment

Sch 6, Pt 2, 9(b)






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 inter-array, 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 intra-array cable layouts are provided in Figures 5.3 to 5.5.



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).



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.



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;



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.



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.



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



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.



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).



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.



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



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

diameter

213mm 258mm

Number of cables See paragraph 5.12.4 3

Total estimated length Up to 300km Up to 190km

Average representative

burial depth used for the

purposes of ES

assessment only

1.5m 1.5m

Burial method Plough / jetting Plough / jetting /

trenching

No. of cable crossings To be confirmed following

design optimisation

Up to 9

Cable protection area for

crossings

To be confirmed following

design optimisation

Up to 3,240m2



Table DCO.9

Section: Offshore cabling Ref DCO constraint


Comment

Sch1, Pt3, 6(2)

The total length of the

cables comprising Work

No. 3A shall not exceed

190 kilometres

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

cables comprising Work

No. 1(e) shall not

exceed 300 kilometres

Any arrangement of intra-array cables

is permitted between any location for

OSP(s) or met mast

Sch1, Pt3, 6(1)

The number of cables

forming part of the


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

Any number of cables of 3 or less may

be installed offshore

Ref Constraint to be applied by deemed Marine Licence Comment

Sch6, Pt2, 9(c)

Requires that a ‘construction method statement’, including details

of cable installation is submitted to, and approved by, the MMO

before marine licensed activities can be undertaken

Will allow MMO to

agree cable burial

depth



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.



Plate 5.20 Example trench to enable intertidal cable burial at GGOWF

Source: GGOWL



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.



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.



Plate 5.22 Typical (simplified) directional drilling arrangement

Source: Balfour Beatty Power Networks Limited

Plate 5.23 Example directional drilling duct

Drilling Site Reception Site



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



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.



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



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



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;

Construction access for vehicles, which needs to allow the safe 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;



Construction access for vehicles, which needs to allow the safe 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.



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).



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

132kV export cables

Up to 3 multicore cables between landfall

and transition bays

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

bay area

5,619m2

Onshore Cable Corridor lengths

(approximate)

Export cables (land fall to transition bays):

260m

132kV export cables (transition bays to GWF

compound): 816m

400kV transmission cables (transmission

compound to sealing end compounds): 275m

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

beyond the transition bays)

Up to 3

Trenching technique

Open trench, with directional drilling

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)

Permanent cable corridor width

Open trench:

23m (GWF 132kV)

19m (Transmission 132/400kV)



Key onshore cable system characteristics

Directional drilling:

33m (GWF 132kV)

Cable trench corridor working width

38m (GWF 132kV)

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.



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


Comment

Sch1, Pt3, 19(3)

No building forming part

of Work Nos. 6, 9A, 9B

or 11, shall exceed the

relevant height limit for

its proposed location

specified on the height

restriction plan above

the approved floor level

for that location

Each of the works items may occupy

any height up to the maximum

permitted and at any location,

potentially covering the entire area.

In practice, an

electrical substation

is a collection of

discrete operational

elements, separated

by service corridors

and maintaining safe

electrical

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

Nos. 6 and 11 shall not

be higher than 9 metres

AOD

Any floor level (for the GWF and

transmission compounds) below 9m

AOD is permitted

The proposed

landform seeks to

achieve a balance

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



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



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.



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.


Final Report Chapter 5 – November 2011

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



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

Maximum building/electrical equipment

height

14m

(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




Number of electrical bays Up to 3

Typical components within each bay

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.

Harmonic filters

Other substation elements

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



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

height

13m (more than 50% of site constrained to 11m)

Typical substation components

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;




Water tank;

Back up diesel generator;

Welfare facilities; and

Security fencing.



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.



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.



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



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.



Table 5.10 Summary of the sealing end compounds and gantries


Compound area

Western compound:

Eastern Compound:

Total area of 0.4ha

Finished floor level (approximate) Western compound: 8.1m

Eastern Compound: 6.8m

Maximum height

(excluding overhead lines, their

connection to the gantry, and cross arms)

13m (gantries)

Tower Replacement cross arms required

Other components

Security fencing

Hard standing

Drop leads

Electrical connection equipment

5.20 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.



Plate 5.28 – Current GGOWF telecommunications mast



Table DCO.11 Section: Relocated telecommunications mast Ref DCO constraint


Comment

Sch1, Pt3, 19(3)

The height of the

relocated

communications mast

shall not exceed 15

metres AOD, and its

supporting pole shall

not exceed 16 metres

AOD

Any height for the equipment and pole

up to 15m and 16m respectively is

permitted.

The maximum

height is likely to be

utilised to maximise

transmission

certainty.

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



Development element Total area

New permanent access roads, turning area and drainage

reserve

0.5ha

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

(working corridor including transition bays and assuming open

cut trenching)

4.4ha

400kV cable corridor between transmission compound and

sealing end compounds

0.7ha

132kV cable corridor between transmission compound and

joint with existing Leiston A 132kV cables

0.8ha

Substation and sealing end compounds temporary laydown

areas (excluding land already covered within cable corridor)

8.2ha

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.



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

handover

12 months Q2 2016

Q2 2017

5.22.2 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



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.



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

geophysical survey

Dedicated geophysical survey vessel using side scan sonar,

multibeam echosounder and magnetometer. Will survey GWF site,

export cable corridor and landfall site.

Pre-construction

geotechnical survey

Dedicated geotechnical survey vessel taking a number of boreholes,

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

infrastructure

foundations

Foundation installation HLV / jack-up barge, possible grouting vessel,

possible foundation transportation vessel and possible support

vessels



Construction aspect

Detail

.

Scour protection Construction barge or dedicated rock placement vessel

WTGs HLV or jack-up barge

Ancillary structures

(OSP, collection

station,

accommodation

platform and met

mast)

HLV or jack-up barge, substation installation vessel

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



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.



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.



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

landfall and transition bays

2 months

Site demobilisation 5 months

Table 5.16 Approximate onshore construction timings for transmission infrastructure

Activity Duration

Site preparation 9 months

Pre-outage works 18 months

Outage works 18 months

Post outage works 2 months

5.24.2 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.



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.



Table 5.17 Summary of construction related traffic

Key traffic

Site preparation 1315 lorries (2630 movements)

GWF Substation 2650 lorries (5300 movements)

Onshore cabling 300 lorries (600 movements)

Transition bays 30 lorries (60 movements)

Directional drilling works 100 lorries (200 movements)

Site demobilisation 213 lorries (426 movements)

Max daily workforce 200. Therefore assume 150 cars per day

(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



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 the following process, with procedures formalising the different stages:

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.



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 O-117 on ‘The Marking of Offshore Wind Farms’ and IALA Recommendation O-114 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.



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).



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.



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.



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.



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

Intermediate – four years

Major – 12 years

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.

Capacitors Routine – annually General visual inspection.

GIS / AIS switchgear Routine – annually

Intermediate – six years

Check gas pressure, check and clean mechanisms and hydraulics; and

Test protection and control equipment.

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.



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.



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;



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.



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.



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.



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 ACO-04-2002 The Crown Estate, (2010). A guide to an Offshore Wind Farm.

november 2011 document reference – 5.2 · november 2011 document reference ... wtg foundations...

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