3. Description of Development

3.1. Introduction

3.1.1.    Overview

  1. This chapter of the Offshore Environmental Impact Assessment (EIA) Report provides a description of the offshore components of the Berwick Bank Wind Farm (the Project) with the offshore components seaward of Mean High Water Springs (MHWS) (hereafter referred to as the Proposed Development). This chapter is based on design work undertaken to date and current understanding of the environment associated with the Proposed Development from site-specific survey work. Specifically, this chapter sets out the individual components associated with the Proposed Development and the activities associated with the construction, operation and maintenance, and decommissioning.
  2. Berwick Bank Wind Farm is a complex Project subject to various design and engineering tasks, technology choices and market trends in the planning phase. The design and engineering options available are dependent on the specific conditions and environmental factors at the site. Studies to address existing unknowns due to the early stage of development and to refine design parameters will continue beyond the planning phase and into procurement and contracting. At Application, the necessary information on the site conditions and the procurement process is unavailable to inform the final Project design. These include final wind turbine number and size, foundation design, wind farm layout, the exact locations of offshore substations, cable type and cable route. The detailed design will be confirmed once consent has been granted, subject to further site investigation.
  3. The Applicant has therefore followed the Project Design Envelope (PDE) approach (also known as the 'Rochdale Envelope') (Scottish Government, 2022). In this chapter, parameters for the Proposed Development are described that include the maximum extents of the design as a basis to determine what the likely worst case effects may be, noting that for some technical topics the worst case might be a combination of parameters, not just the maximum parameter, as explained and assessed in volume 2, chapters 7 to 21. The ‘maximum design envelope’ presented in this chapter defines the maximum range of design parameters. For the EIA, the Applicant has discerned the maximum impacts that could occur for given receptor groups, selecting these from within the range of the design parameters (maximum design envelope’) to define the “maximum design scenario” for that receptor group.
  4. As time progresses, and additional information is available from site investigations and commercial availability of technologies, increased certainty can be provided over Project details to inform the final detailed design. This approach is standard for large scale energy projects such as the Project.

3.1.2.    Purpose of this Chapter

  1. The purpose of this Offshore EIA Report chapter is:
  • to provide the maximum PDE for the Proposed Development which consent is being sought for, comprising information on the site, design, size and other relevant features of the Proposed Development, based on preliminary conceptual design principles (section 3.1.4) and current understanding of the environment;
  • to set out the individual components of the Proposed Development, as well as the main activities associated with the construction, operation and maintenance and decommissioning phases; and
  • to provide the basis for the assessment of effects included in volume 2, chapters 7 to 21.

3.1.3.    Project Design Envelope

  1. The PDE approach provides flexibility while ensuring all potential likely significant effects (beneficial or adverse) are assessed within the Offshore EIA process and reported in the Offshore EIA Report. Project parameters presented include a range of potential values up to and including the maximum Project design parameters.
  2. The Proposed Development’s PDE has been designed to include sufficient flexibility to accommodate further Project refinement during the final design stage. For each of the impacts assessed within the technical assessments (volume 2, chapters 7 to 21), the maximum design scenario has been identified from the range of potential options for each parameter set out in the PDE which is described in this chapter. By employing the maximum design scenario approach, the Applicant retains some flexibility in the final design of the Proposed Development and associated offshore infrastructure, but within certain maximum parameters, which are assessed in this Offshore EIA Report. Based on the PDE, this Project Description chapter provides the maximum scenario, thus anything less than that set out in the Project Description chapter and assessed within the technical assessments will have a lesser impact.
  3. This approach is in line with Scottish Government (2013) guidance, which states that ‘by applying the principles of an approach commonly known as the 'Rochdale Envelope' it is possible to undertake an environmental assessment which takes account of the need for flexibility in the future evolution of the detailed Project proposal, within clearly defined parameters. In such cases, the level of detail of the proposals must be sufficient to enable a proper assessment of the likely significant environmental effects, and any resultant mitigation measures - if necessary, considering a range of possibilities.’ The approach is also compliant with the guidance prepared by Marine Scotland and the Energy Consents Unit in June 2022 for applicants using the design envelope for applications under section 36 of the Electricity Act 1989 (Scottish Government, 2022).
  4. The PDE approach applies a “maximum design scenario” that considers a realistic range of Project parameters (or scenarios). The PDE describes a range of parameters that apply to a Project technology design scenario (e.g. largest wind turbine option). For example, wind turbine size and wind turbine number are inherently correlated (e.g. if larger wind turbines are selected), fewer wind turbines are likely to be required. Therefore, each design parameter set out in this chapter are not considered independently. The maximum design scenario developed for each impact pathway has been taken from the PDE to establish the parameters (or combination of parameters) likely to result in the maximum effect (e.g. the maximum adverse scenario), while adhering to the Project technology design scenarios (e.g. infrastructure parameters associated with the largest wind turbine size). However, it does not follow necessarily that the largest parameters set out in this chapter comprise the maximum design scenario for any given receptor group and each of the impacts assessed within the technical assessments (volume 2, chapters 7 to 21).
  5. In June 2022, revisions to the Proposed Development site boundary were announced. The revisions comprise a reduction in the Proposed Development array area, including to the north and western areas of the Proposed Development site boundary. This resulted in an approximate reduction in the overall area of the Proposed Development array area of 23% (when compared to the Proposed Development included in the Berwick Bank Wind Farm Offshore Scoping Report submitted in October 2021 (SSER, 2021a). Further detail is included in the Site Selection and Consideration of Alternatives chapter (volume 1, chapter 4), however, in general, the following adjustments have been made to the Proposed Development project description for the Proposed Development:
  • revised boundary for Proposed Development array area;
  • revised indicative wind turbine layouts;
  • revised indicative construction programme;
  • removal of open cut trench techniques at landfall;
  • removal of the landfall option at Thorntonloch;
  • reduction in the number offshore export cables from eight to 12 and refinement of the Proposed Development export cable corridor to account for the array boundary change;
  • updated estimates to vessel numbers and movements; and
  • revised approach to decommissioning.
    1. In light of the revisions to the Proposed Development array area boundary it has been necessary to amend the PDE accordingly. Consequently, the PDE used in this Offshore EIA Report differs from that presented in the Berwick Bank Wind Farm Offshore Scoping Report submitted in October 2021 (SSER, 2021a). The latest PDE parameters for infrastructure seaward of MHWS are included in this Project Description chapter.
    2. The derogation provisions within the Habitats Regulations Appraisal (HRA) process may require the Applicant to provide compensatory measures to compensate for the potential adverse effects on the integrity of European sites resulting from the Proposed Development either alone or in combination with other plans and projects. In anticipation of the potential need for compensation measures, the Applicant has undertaken an appraisal of the potential impacts of the compensatory measures proposed (without prejudice to the HRA to be conducted by the Competent Authority). The outcomes of the bespoke EIA and HRA of the compensation options for the Proposed Development are provided alongside the Application.

3.1.4.    Location and Site Information

  1. The Proposed Development will be located in the central North Sea, approximately 47.6 km offshore of the East Lothian coastline and 37.8 km from the Scottish Borders coastline at St, Abbs. As described in volume 1, chapter 4, the Proposed Development is already the subject of Agreements for Lease (AfL) from Crown Estate Scotland (CES). The Proposed Development’s assumed operational lifetime is 35 years, as described in volume 1,chapter 1.

Proposed Development boundary

  1. The Proposed Development boundary is illustrated within Figure 3.1   Open ▸ and covers an area of 1,178.1 km2. This area encompasses the:
  • Proposed Development array area (an area of 1,010.2 km2): this is where the offshore wind farm will be located, which will include the wind turbines, wind turbine foundations, inter-array cables, and a range of offshore substations and offshore interconnector cables; and
  • Proposed Development export cable corridor up to MHWS (an area of 167.9 km2): this is where the offshore electrical infrastructure such as offshore export cables and associated cable protection will be located.

Water depths and seabed within the Proposed Development array area

  1. A geophysical survey was undertaken across the Proposed Development array area in 2019, providing geophysical and bathymetric data. The bathymetry of the Proposed Development array area is influenced by the presence of large scale morphological bank features of the ‘Marr Bank’ and ‘Berwick Bank’ ( Figure 3.1   Open ▸ ). These two bank features are defined as ‘Shelf Banks and Mounds’ and are part of the Firth of Forth Banks Complex Marine Protected Area (MPA).
  2. A maximum seabed depth is recorded at two locations where deep channels cut into the seabed east and west of the central point of the Proposed Development array area (68.5 m Lowest Astronomical Tide (LAT)). The shallowest area is observed in the west of the Proposed Development array area (33.4 m LAT). The average seabed depth across the Proposed Development array area is 51.7 m below LAT. The shallower areas are coincidental with the two large sand bank features that are present in the Proposed Development site boundary.
  3. Further details of the bathymetry and a description of the seabed composition at the Proposed Development array area are presented within volume 2, chapters 7 and 8.

Figure 3.1:
Location of the Proposed Development Array Area and Export Cable Corridor and the Firth of Forth Morphological Banks

Figure 3.1: Location of the Proposed Development Array Area and Export Cable Corridor and the Firth of Forth Morphological Banks

3.1.5.    Proposed Development export cable corridor

  1. The Proposed Development export cable corridor identified commences at the southern/south-western boundary of the Proposed Development array area and makes landfall at Skateraw on the East Lothian coast.
  2. The bathymetry along the Proposed Development export cable corridor ranges from the low water mark to a depth of 69.8 m below LAT. Further details of the bathymetry and a description of the seabed composition at the Proposed Development export cable corridor are presented within volume 2, chapters 7 and 8.

3.2. Offshore Infrastructure

3.2.1.    Overview

  1. The key offshore components of the Proposed Development (seaward of MHWS), as shown in Figure 3.2   Open ▸ , will include:
  • up to 307 wind turbines (each comprising a tower section, nacelle and three rotor blades) and associated support structures and foundations;
  • up to ten Offshore Substation Platforms (OSPs)/Offshore convertor station platforms and associated support structures and foundations to accommodate for a combined High Voltage Alternating Current (HVAC)/High Voltage Direct Current (HVDC) transmission system solution or a HVDC solution;
  • estimated scour protection of up to 10,984 m2 per wind turbine and 11,146 m2 per OSP/Offshore convertor station platforms;
  • a network of inter-array cabling linking the individual wind turbines to each other and to the OSPs/Offshore convertor station platforms plus inter-connections between OSPs/Offshore convertor station platforms (approximately 1,225 km of inter-array cabling and 94 km of interconnector cabling); and
  • up to eight offshore export cables connecting the OSPs/Offshore convertor station platforms to landfall at Skateraw. Offshore export cable design includes both HVAC and HVDC solutions.
    1. The Applicant is also developing an additional export cable and grid connection to Blyth, Northumberland (hereafter the “Cambois connection”). Applications for the necessary consents (including marine licences) will be applied for separately once further development work has been undertaken on this offshore export corridor. The Cambois connection has been included as a cumulative project for the purposes of the offshore EIA and assessed based on the information presented in the Cambois connection Scoping Report submitted in October 2022 (SSER, 2022e). An EIA and HRA will be prepared to support any relevant consent applications that are required to deliver the Cambois connection which will also consider cumulative effects with the Proposed Development.

Figure 3.2:
Project Overview[1]

Figure 3.2: Project Overview[1]

 

3.2.2.    Wind Turbines

  1. The Proposed Development will comprise up to 307 wind turbines, with the final number of wind turbines dependent on the capacity of individual wind turbines used, and also environmental and engineering survey results. The PDE considers a range of wind turbines with parameters reflective of potential generating capacities, allowing for a degree of flexibility to account for any anticipated developments in wind turbine technology while still allowing each of the impacts assessed within the technical assessments (volume 2, chapters 7 to 21), to define the maximum design scenario for the assessment of effects. Consent is therefore sought for the physical parameters of the wind turbines which form the basis of the maximum design scenario such as maximum tip height or rotor diameter, as presented in the PDE rather than actual installed capacity of the wind turbines.
  2. A range of wind turbine options have been considered. The parameters in Table 3.1   Open ▸ provide for both the maximum number of wind turbines, as well as the largest wind turbine within the PDE. As set out in paragraph 8, the coupling of these maximum dimensions will not provide a realistic design scenario; as a reduced number of wind turbines will likely be required if an increased rated output of wind turbine model is chosen. Table 3.1   Open ▸ describes the maximum parameters that apply.
  3. The wind turbines will comprise a horizontal axis rotor with three blades connected to the nacelle of the wind turbine. Figure 3.3   Open ▸ illustrates a schematic of a typical offshore wind turbine.

Figure 3.3:
Indicative Schematic of an Offshore Wind Turbine on a Jacket Foundation

Figure 3.3: Indicative Schematic of an Offshore Wind Turbine on a Jacket Foundation

 

  1. The maximum rotor blade diameter will be no greater than 310 m, with a maximum blade tip height of 355 m above LAT and a minimum lower blade tip height of 37 m above LAT. A scheme for wind turbine lighting and navigation marking will be approved by Scottish Ministers following consultation with appropriate consultees post consent. Outlines plans have been provided with the Application in volume 4 of this Offshore EIA Report.
  2. The layout of the wind turbines will be developed to best utilise both the available wind resource, suitability of seabed conditions and wake effects, while seeking to minimise environmental effects and impacts on other marine users (such as fisheries and shipping routes).
  3. Figure 3.4   Open ▸ presents an indicative wind farm layout based on the maximum design scenario of 307 wind turbines, while Figure 3.5   Open ▸ displays an indicative wind farm layout should 179 wind turbines were to be installed. The final layout of the wind turbines will be confirmed at the final design stage post consent with details being submitted to Marine Scotland Licensing Team (MS-LOT) for approval.
Table 3.1:
Design Envelope: Wind Turbines

Table 3.1: Design Envelope: Wind Turbines

Figure 3.4:
Berwick Bank Wind Farm Preliminary Indicative Layout for 307 Wind Turbines Each Square Being 5 km x 5 km)

Figure 3.4: Berwick Bank Wind Farm Preliminary Indicative Layout for 307 Wind Turbines Each Square Being 5 km x 5 km)

Figure 3.5:
Berwick Bank Wind Farm Preliminary Indicative Layout for 179 Wind Turbines Each Square Being 5 km x 5 km)

Figure 3.5: Berwick Bank Wind Farm Preliminary Indicative Layout for 179 Wind Turbines Each Square Being 5 km x 5 km)

 

  1. To improve operation, productivity and prevent wear on parts, a number of consumables may be required for the wind turbines. These may include:-

Wind turbine foundations and support structures

  1. To allow for flexibility in foundation choice, two types of wind turbine support structures and foundations are being considered for the Proposed Development:
  • piled jacket; and
  • suction caisson jacket.
    1. Foundations will be fabricated offsite, stored at a suitable port facility (if required) and transported to site by sea. Specialist vessels will transport and install foundations. Scour protection (typically rock) may be required on the seabed and will be installed before and/or after foundation installation. The following section provides an overview of the foundation types which are being considered for wind turbines - foundation structures for OSPs/Offshore convertor station platforms are discussed in section 3.2.3.

Piled jacket foundation

  1. The piled jacket foundations will be transported to site by sea. Once at site, the jacket foundation will be lifted by the installation vessel using a crane and lowered towards the seabed in a controlled manner. Piled jacket foundations are formed of a steel lattice construction (comprising tubular steel members and welded joints) secured to the seabed by driven and/or drilled pin piles attached to the jacket feet (as illustrated in Figure 3.6   Open ▸ ). The hollow steel pin piles are typically driven or drilled into the seabed, relying on the frictional and end bearing properties of the seabed for support. The PDE for jacket foundations with pin piles is provided in Table 3.2   Open ▸ .

 

Table 3.2:
Design Envelope: Wind Turbine Jacket Foundation with Pin Piles

Table 3.2: Design Envelope: Wind Turbine Jacket Foundation with Pin Piles

Figure 3.6:
Indicative Schematic of a Jacket Foundation with Pin Piles

Figure 3.6: Indicative Schematic of a Jacket Foundation with Pin Piles

 

Suction caisson jacket foundations

  1. Suction caisson jacket foundations are formed with a steel lattice construction (comprising tubular steel members and welded joints) fixed to the seabed by suction caissons installed below each leg of the jacket (as per Figure 3.7   Open ▸ ). The suction caissons are typically hollow steel cylinders, capped at the upper end, which are fitted underneath the legs of the jacket structure. They do not require a hammer or drill for installation.
  2. The suction caisson jacket foundations will be transported to site by sea. Once at site, the jacket foundation will be lifted by the installation vessel using a crane and lowered towards the seabed in a controlled manner. When the steel caisson reaches the seabed, a pipe running up through the stem above each caisson will begin to suck water out of each bucket. The buckets are pressed down into the seabed by the resulting suction force. When the bucket has penetrated the seabed to the desired depth, the pump is turned off. A thin layer of grout is then injected under the bucket to fill the air gap and ensure contact between the soil within the bucket, and the top of the bucket itself. The PDE for jacket foundations with suction caissons is provided in Table 3.3   Open ▸ .

 

Table 3.3:
Design Envelope: Wind Turbine Jacket Foundation with Suction Caisson

Table 3.3: Design Envelope: Wind Turbine Jacket Foundation with Suction Caisson


Figure 3.7:
Indicative Schematic of a Jacket Foundation with Suction Caissons

Figure 3.7: Indicative Schematic of a Jacket Foundation with Suction Caissons

 

3.2.3.    Offshore Substation Platforms and Offshore Convertor Station Platforms

  1. The Applicant has three signed grid connection agreements with the network operator. Two agreements are for connection at the Branxton substation, with a third additional connection at Blyth, Northumberland (the Cambois connection). The Cambois connection agreement, was confirmed in June 2022 following National Grid’s Electricity System Operator (NGESO) Holistic Network Review, and will enable the Project to reach full generating capacity (4.1 GW) by early 2030’s.
  2. The installation of offshore export cables including landfall methodologies for the Cambois connection is being consented separately to the Proposed Development but has been considered cumulatively as part of this Application.
  3. The Project is currently considering HVAC and HVDC solutions for the Offshore Transmission Infrastructure. These solutions include:

–           up to eight HVAC OSPs to facilitate connections to Branxton and two HVDC Offshore convertor station platforms that will be required for the Cambois connection (see Table 3.4   Open ▸ ); or

–           up to five larger HVAC OSPs to facilitate connections to Branxton and two HVDC Offshore convertor station platforms that will be required for the Cambois connection (see Table 3.5   Open ▸ ).

  • HVDC Option: Up to five HVDC Offshore convertor station platforms, two for the Branxton connection and two for the additional Cambois connection (see Table 3.6   Open ▸ ) This also includes an offshore interconnector platform.
    1. These offshore platforms will be utilised as OSPs/Offshore convertor stations platforms which transform electricity generated by the wind turbines to a higher voltage and thereby allowing the power to be efficiently transmitted to shore. The platforms’ topsides size will depend on the final electrical design for the wind farm but maximums could be up to 100 m (length) by 80 m (width) and up to 80 m in height (above LAT), excluding the helideck, antenna structure or lightning protection. The maximum design parameters for OSPs/Offshore convertor station platforms are presented in Table 3.4   Open ▸ and Table 3.5   Open ▸ (Combined Options) and Table 3.6   Open ▸ (HVDC Option). It is proposed that the OSP/Offshore convertor station platform foundations will be painted yellow from the water line up to the topside structure and the topside will be painted light grey.

 

Table 3.4:
Design Envelope: OSP/Offshore Convertor Station Platform (Combined Option A)

Table 3.4: Design Envelope: OSP/Offshore Convertor Station Platform (Combined Option A)

 

Table 3.5:
Design Envelope: OSP/Offshore Convertor Station Platform (Combined Option B)

Table 3.5 Design Envelope: OSP/Offshore Convertor Station Platform (Combined Option B)

Table 3.6:
Design Envelope: Offshore Convertor Station Platforms (HVDC Option)

Table 3.6: Design Envelope: Offshore Convertor Station Platforms (HVDC Option)

 

  1. Table 3.7   Open ▸ presents the consumables which will be required for the OSPs/Offshore convertor station platforms at the Proposed Development. In addition, Uninterruptible Power Supply (UPS) batteries, fire suppression systems, HVAC coolant and SF6 will also be required.

 

Table 3.7:
Design Envelope: Consumables for the Offshore Substation Platforms (per OSP/Offshore Convertor Station Platform)

Table 3.7: Design Envelope: Consumables for the Offshore Substation Platforms (per OSP/Offshore Convertor Station Platform)

 

  1. Project design layout has not yet been finalised, however the OSPs/Offshore convertor station platforms will be located within the Proposed Development array area. The offshore platforms will be installed with piled jacket foundations or suction caissons, as described in section 3.2.2. The PDE for offshore platforms piled jacket foundations is shown in Table 3.8   Open ▸ (Combined Option A), Table 3.9   Open ▸ (Combined Option B) and Table 3.10   Open ▸ (HVDC Option). The PDE for offshore platforms suction caissons foundations is shown in Table 3.11   Open ▸ (Combined Option A), Table 3.12   Open ▸ (Combined Option B) and Table 3.13   Open ▸ (HVDC Option).

 

Table 3.8:
Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (Combined Option A)

Table 3.8: Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (Combined Option A)

 

Table 3.9:
Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (Combined Option B)

Table 3.9 Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (Combined Option B)

 

Table 3.10:
Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (HVDC Option)

Table 3.10: Maximum Design Envelope: Jacket Foundation with Pin Piles for OSPs/Offshore Convertor Station Platforms (HVDC Option)

 

Table 3.11:
Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (Combined Option A)

Table 3.11: Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (Combined Option A)

 

Table 3.12:
Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (Combined Option B)

Table 3.12: Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (Combined Option B)

 

Table 3.13:
Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (HVDC Option)

Table 3.13: Maximum Design Envelope: Suction Caisson Foundation for OSPs/Offshore Convertor Station Platforms (HVDC Option)

 

3.2.4.    Scour Protection for Foundations

  1. Foundation structures for wind turbines and substations are at risk of seabed erosion and ‘scour hole’ formation due to natural hydrodynamic and sedimentary processes. The development of scour holes is influenced by the shape of the foundation structure, seabed sedimentology and site-specific metocean conditions such as waves, currents and storms. Scour protection may be employed to mitigate scour around foundations. There are several commonly used scour protection types, including:
  • concrete mattresses: several metres wide and long, cast of articulated concrete blocks which are linked by a polypropylene rope lattice which are placed on and/or around structures to stabilise the seabed and inhibit erosion;
  • rock placement: either layers of graded stones placed on and/or around structures to inhibit erosion or rock filled mesh fibre bags which adopt the shape of the seabed/structure as they are lowered on to it; or
  • artificial fronds: mats typically several metres wide and long, composed of continuous lines of overlapping buoyant polypropylene fronds that create a drag barrier which prevents sediment in their vicinity being transported away. The frond lines are secured to a polyester webbing mesh base that is itself secured to the seabed by a weighted perimeter or anchors pre-attached to the mesh base.
    1. The most frequently used scour protection method is ‘rock placement’, which entails the placement of crushed rock around the base of the foundation structure.
    2. The amount of scour protection required will vary for the two foundation types being considered for the Proposed Development. The final choice of scour protection will be made after design of the foundation structure, taking into account a range of aspects including geotechnical data, meteorological and oceanographical data, water depth, foundation type, maintenance strategy and cost. Scour protection PDE parameters for foundations with piled jackets and suction caissons are presented in Table 3.14   Open ▸ .

Table 3.14:
Scour Protection Parameters – Wind Turbine Foundations and OSP/Offshore Convertor Station Platform

Table 3.14: Scour Protection Parameters – Wind Turbine Foundations and OSP/Offshore Convertor Station Platform

 

3.2.5.    Subsea Cables

  1. The type of cable laying vessel that will be used to lay subsea cables on the seabed has not been selected at this time. Therefore, the maximum design envelope accounts for both the use of a Dynamic Positioning (DP) vessel and vessels which require the use of anchor during cable laying activities (see Table 3.15   Open ▸ to Table 3.18   Open ▸ ).

Inter-array cables

  1. Inter-array cables carry the electrical current produced by the wind turbines to an offshore substation platform or an offshore convertor station platform. A small number of wind turbines will typically be grouped together on the same cable ‘string’ connecting those wind turbines to the substation/convertor platform, and multiple cable ‘strings’ will connect back to each offshore substation/convertor platform.
  2. The inter-array cables will be buried where possible and protected with a hard protective layer (such as rock or concrete mattresses) where adequate burial is not achievable, for example where crossing pre-existing cables, pipelines or exposed bedrock. The requirement for additional protection will be dependent on achieving target burial depths which will be influenced by several factors such as seabed conditions, seabed sedimentology, naturally occurring physical processes and possible interactions with other activities including bottom trawled fishing gear and vessel anchors. There is the potential for seabed preparation to be required prior to cable installation with methods such dredge and deposit of sediments material, use jet trenchers, mechanic trenchers or grapnels currently being considered. The cable installation methodology and potential cable protection measures will be finalised at the final design stage (post-consent). The PDE for inter-array cables is presented in Table 3.15   Open ▸ .

 

Table 3.15:
Design Envelope: Inter-Array Cables

Table 3.15: Design Envelope: Inter-Array Cables

 

Interconnector cables

  1. Interconnector cables will be required to connect the OSPs/Offshore convertor station platforms to each other in order to provide redundancy in the case of failures within the electrical transmission system. The cables are likely to consist of a cross-linked polyethylene (XLPE) insulated aluminium or copper conductor cores.
  2. These cables will be either HVDC or a combination of HVDC and HVAC. Table 3.16   Open ▸ provides the maximum design scenario for interconnector cables.
  3. The interconnector cables will have a minimum target burial depth of 0.5 m. If burial is not possible due to ground conditions or target burial depths not being achievable, then cable protection techniques will be employed (paragraph 55). The total length of interconnector cables will not exceed 94 km. There is the potential for seabed preparation to be required prior to cable installation with methods such dredge and deposit of sediments material, use jet trenchers, mechanic trenchers or grapnels currently being considered.

 

Table 3.16:
Design Envelope: Interconnector Cables

Table 3.16: Design Envelope: Interconnector Cables

 

Offshore export cables

  1. Offshore export cables are used for the transfer of power from the OSPs/Offshore convertor station platforms to the transition join bay at landfall where they become onshore export cables. Up to eight offshore export cables will be required (applicable to both Combined and HVDC Options).
  2. The offshore export cables will have a maximum total length of 872 km, comprised of up to eight cables connecting the OSPs/Offshore convertor station platforms to landfall at Skateraw. Each of these offshore export cables will be installed in a trench up to 2 m wide with a target burial depth of between 0.5 m and 3 m per cable.
  3. Although the Proposed Development export cable corridor has been identified, the exact route of the offshore export cables is yet to be determined and will be based upon geophysical and geotechnical survey information. This information will also support the decision on requirements for any additional cable protection. Flexibility is required in the location, depth of burial and protection measures for the offshore export cables to ensure physical and technical constraints, changes in available technology and Project economics can be accommodated within the final design.
  4. The proposed method for the installation of the offshore export cables through the intertidal zone at landfall at Skateraw is by using a trenchless technique burial method ( Figure 3.9   Open ▸ ). Following punch out of offshore export cables, onwards installation to the wind farm will be completed by using jetting, trenching and ploughing as summarised in Table 3.17   Open ▸ , noting pre-sweeping/dredging may be required in some areas.

 

Table 3.17:
Design Envelope: Offshore Export Cable Method of Installation

Table 3.17: Design Envelope: Offshore Export Cable Method of Installation

 

  1. The maximum design scenario for the offshore export cables is described in Table 3.18   Open ▸ .

 

Table 3.18:
Design Envelope: Offshore Export Cables

Table 3.18: Design Envelope: Offshore Export Cables