3. Consultation to Date

46. To date, consultation has been undertaken with relevant statutory stakeholders during key stages of the pre-application phase of the Array.
47. Consultation was undertaken with MD-LOT, NatureScot, and Natural England, alongside various other stakeholders, such as the Scottish Fishermen’s Federation (SFF) and the Scottish Environmental Protection Agency (SEPA). Consultation feedback was received in November 2022, following information presented at the Array EIA Scoping Workshop. Following this, consultation representation and advice with respect to the Array HRA Stage One LSE2 Screening Report were received along with the Ossian Array Scoping Opinion in June 2023 (MD-LOT, 2023). Consultation applicable to this RIAA has been taken into consideration, as appropriate, and is summarised, where relevant to SACs and SPAs, in Part 2 and Part 3 of this RIAA, respectively.
48. Based on the outcomes of the Array HRA Stage One LSE2 Screening Report, no potential significant transboundary effects, either alone or in-combination, were predicted for the Array. Therefore, no transboundary consultation has been carried out with respect to this RIAA.

4. Information on the Array

49. This section provides an outline of the Array and describes the activities likely to be associated with the construction, operation and maintenance, and decommissioning phases of the Array. It summarises the design and components of the Array infrastructure, based on conceptual design information and refinement of the Array parameters.

4.1. Project Design Envelope

50. The Project Design Envelope (PDE) approach (also known as the 'Rochdale Envelope') (Scottish Government, 2022) has been followed by the Applicant, meaning that parameters for the Array included in this section present the maximum extent of the design in order to assess the maximum adverse effects of the Array. The ‘maximum design envelope’ (e.g. the Maximum Design Scenario (MDS)) presented in this section defines the maximum range of design parameters. Through the MDS approach the Applicant has determined the maximum impacts that could occur for given receptor groups, selecting these from within the range of the ‘maximum design envelope’ to define the MDS for that receptor group and potential impact pathway. As a result, the predicted effects assessed in Part 2 and Part 3 of this RIAA will be no greater for any alternative parameters .
51. The final detailed design will be further developed post-consent, as additional information becomes available from site investigations and commercial availability of technologies. It should be noted that the final detailed design for the Array will be within the PDE parameters presented in this section. This is a standard approach for large scale energy projects such as the Array.
52. The PDE approach allows for flexibility in the final Array design to account for supply chain constraints and selection of the most appropriate technology for the site and conditions, while allowing for an appropriate assessment of the Array on designated sites in view of their conservation objectives, as reported within the RIAA. The PDE presents a range of potential parameter values up to and including the maximum Array design parameters.
53. The Array PDE has been designed to allow for sufficient flexibility in the final project design options and further refinement during the final design stage, where the full details of a project are not known at the point of Application submission. For each of the impacts assessed within Part 2 and Part 3 of this RIAA, the PDE has been reviewed and the MDS has been identified from the range of potential options for each parameter. The MDS approach allows the Applicant to retain some flexibility in the final design of the Array and associated offshore infrastructure, but certain maximum parameters are set and are assessed in this RIAA.
54. The MDSs, as per the PDE, are presented in Part 2 and Part 3 of this RIAA. Anything less than that set out within this section and assessed within Part 2 and Part 3 of this RIAA will have a lesser impact.
55. The PDE describes a range of parameters that apply to a Project technology design scenario (e.g. largest wind turbine option). In this example, wind turbine size and wind turbine number are inherently correlated so if larger wind turbines are selected, fewer wind turbines are likely to be required. Therefore, each design parameter set out in this section is not considered independently. The PDE has been used to develop the MDS for each impact pathway in order to determine the parameters (or combination of parameters) which are likely to result in the maximum effect (e.g. the MDS) on a particular receptor. It should be noted, however, that the largest parameters set out in this section will not necessarily comprise the MDS for any given receptor group and each of the impacts assessed in Part 2 and Part 3 of the RIAA.
56. Since the submission of the Array EIA Scoping Report (Ossian OWFL, 2023) and the Array HRA Stage One LSE2 Screening Report (appendix 1A), the Applicant has developed and refined the PDE for the RIAA using the results of early engineering studies and information gained through consultation with stakeholders. A full description of PDE refinements for the Array is provided within volume 1, chapter 4 of the Array EIA Report, however, a summary is provided in Table 4.1   Open ▸ .

Table 4.1: Overview of PDE Refinements for the Array

57. The HRA process includes derogation provisions which may require the Applicant to provide measures to compensate for the adverse effects on the integrity of European sites resulting from the Array, either alone, or in combination with other plans and projects. 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). An EIA Likely Significant Effect (LSE1) and HRA LSE2 Assessment has been undertaken on the proposed compensation measures for the Array and are provided as part of the Application.

4.2. Location and Site Information

58. The Array will be located within the site boundary, located off the east coast of Scotland, approximately 80 km south-east of Aberdeen from the nearest point, and comprising an area of approximately 859 km2 ( Figure 1.1   Open ▸ ).  
59. In January 2022, as part of the ScotWind Leasing Round, the Applicant was awarded an Option to Lease Agreement to develop Ossian, an offshore wind farm project within the E1 PO Area (see volume 1, chapter 4 of the Array EIA Report for further information on the site selection process).

4.2.1. Water depths and seabed within the Array

60. A geophysical survey covering the area within the site boundary was conducted between March 2022 and July 2022 to collect geophysical and bathymetric data. Across the site boundary, the maximum water depth was recorded at 88.7 m LAT, and the shallowest area was recorded at 63.8 m LAT. The seabed across the site boundary slopes gently downwards in an approximately north-west to south-east direction (Ocean Infinity, 2022).
61. Seabed sediments within the site boundary are significantly dominated by deep circalittoral sand, with one area of limited extent comprised of deep circalittoral coarse sediment within the northern part of the site (European Marine Observation and Data Network (EMODnet), 2023). The geophysical survey indicated that the seabed comprises mainly of sand, with areas of gravel in the west of the site boundary (Ocean Infinity, 2022). The seabed within the site boundary is generally flat, with mega-ripples and sand waves observed in the north-west of the site. Furrows were observed occasionally across the site boundary, more commonly in the west (Ocean Infinity, 2022).
62. Further details of the bathymetry and seabed composition are presented within volume 2, chapters 7 and 8 of the Array EIA Report.

4.3. Array Infrastructure

4.3.1. Overview

63. The main components of the Array will include:

• up to 265 floating wind turbines (each comprising a tower section, nacelle, hub and three rotor blades) and associated floating foundations;
• mooring and anchoring systems for each floating foundation;
• connectors and ancillaries for mooring and anchoring systems, including buoyancy elements and clump weights;
• up to six large OSPs, or up to three large OSPs and up to 12 small OSPs with fixed jacket foundations;
• scour protection for wind turbine anchoring systems;
• scour protection for small and large OSP fixed foundations as required;
• a network of dynamic/static inter-array cabling linking the individual floating wind turbines to OSPs, and interconnector cables between OSPs (approximately 1,261 km of inter-array cabling and 236 km of interconnector cabling); and
• discrete condition monitoring equipment (such as sensors, cameras, dataloggers etc.), as required for safe and efficient operation of the Array infrastructure.

4.3.2. Floating Wind Turbines

64. The Array will comprise up to 265 floating wind turbines, however, the final number of wind turbines will be dependent on the capacity of individual wind turbines used, as well as the environmental and engineering survey results.
65. A range of wind turbine parameters are provided which account for varying generating capacities of wind turbines considered within the PDE. This allows a degree of flexibility to account for anticipated technological developments in the future whilst allowing the MDS to be defined for each potential impact within the RIAA. Therefore, the wind turbine parameters presented in this section, and for which consent is being sought, represent the maximum wind turbine parameters as presented in the PDE, such as maximum rotor blade diameter and maximum blade tip height.
66. Table 4.2   Open ▸ presents the range of parameters considered for the wind turbines and considers both the maximum number of wind turbines and the largest wind turbines described within the PDE. Therefore, the parameters in combination do not represent a realistic design scenario, rather they represent the most adverse parameters of a range of wind turbine models that may be available post-consent/at the time of the Array construction.
67. Floating wind turbines will comprise a tower section, nacelle, hub and three rotor blades, and will be attached to a floating foundation. A schematic of a typical floating wind turbine is presented in Figure 4.1   Open ▸ .
68. The maximum rotor blade diameter will be no greater than 350 m, with a maximum blade tip height of up to 399 m above LAT and minimum blade clearance of 36 m above LAT. The hub height will be no greater than 224 m above LAT. The Applicant will develop and agree a scheme for wind turbine lighting and navigation marking with the relevant consultees post-consent decision for approval by Scottish Ministers after consultation with appropriate consultees.
69. The wind turbine layout will be developed to effectively make use of the available wind resource and suitability of seabed conditions, whilst ensuring that the environmental effects and potential impacts on other marine users (e.g., fisheries and shipping routes) are reduced. If required by consent conditions, confirmation of the final layout of the wind turbines will occur at the final design stage (post-consent) in consultation with relevant stakeholders and submitted to the MD-LOT for approval. Indicative array layouts are presented in Figure 4.2   Open ▸ and Figure 4.3   Open ▸ for 265 wind turbine locations plus 15 OSP locations and 130 wind turbine locations plus 15 OSP locations, respectively. The OSPs could be sited at any of the locations shown in the figures and will be determined at the final design stage (post-consent). Further information on OSPs is provided in section 4.3.4.

Table 4.2: Maximum Design Envelope: Floating Wind Turbines

Figure 4.1: Schematic of a Typical Floating Wind Turbine

Figure 4.2: Preliminary Array Layout Comprising up to 265 Wind Turbines and up to 15 OSP Locations

Figure 4.3: Preliminary Array Layout Comprising up to 130 Wind Turbines and up to 15 OSP Locations

70. A number of consumables will be required throughout the Array’s lifecycle to improve operation, productivity and reduce wear on parts of wind turbines. These may include:

• grease;
• synthetic oil;
• hydraulic oil;
• gear oil;
• lubricants;
• nitrogen;
• water/glycerol;
• transformer silicon/ester oil;
• diesel fuel;
• Sulphur Hexafluoride; and
• glycol/coolants.

71. Required quantities of each consumable will be dependent upon the final design of the wind turbine selected. Potential release of any chemicals into the marine environment via an accidental pollution event during the construction, operation and maintenance and decommissioning phases will be reduced as far as reasonably practicable through implementation of appropriate controls and mitigation as set out in an Environmental Management Plan (EMP), including a Marine Pollution Contingency Plan (MPCP), and the Decommissioning Programme. An outline EMP, including an outline MPCP, is presented in volume 4, appendix 21 of the Array EIA Report.

4.3.3. Floating Wind Turbine Foundations and Support Structures

72. The Array will comprise floating wind turbines supported by floating foundations which require mooring and anchoring systems to maintain station. The following subsections describe the MDS for the floating foundations, mooring systems, and anchoring systems.

                        Floating foundations

73. An overview of the floating foundation options considered for the Array is provided in Figure 4.4   Open ▸ and Table 4.3   Open ▸ . Each floating technology has varying dimensions as a result of the differing approach to meeting the unique engineering challenges associated with floating wind turbines, floating structure site specific design, wind turbine sizes and project specific requirements. The final floating foundation design may look different to those pictured but will follow the same design principles. The following floating foundation solutions are being considered for the Array:

• Semi-submersible: A buoyancy stabilised platform which floats semi-submerged on the sea surface whilst anchored to the seabed. The structure gains its stability through the buoyancy force associated with its large footprint (relative to the spar solution) and geometry, which ensures the wind loadings on the floating foundation and wind floating turbine are countered/dampened by the equivalent buoyancy force on the opposite side of the structure. Other configurations, similar to semi-submersibles with regards to footprint, draft and mooring arrangement, like buoy floaters, are also being considered.  It should be noted that semi-submersible foundations are applicable for use with catenary, semi taut and taut mooring systems.
• Tension Leg Platform (TLP): A TLP is a semi-submerged buoyant structure, anchored to the seabed with tensioned mooring lines (tendon). The combination of the structure buoyancy and tension in the anchor and mooring system provides the platform stability. This system stability (as opposed to the stability coming from the floating foundation itself) allows for a smaller and lighter floating foundation.

Figure 4.4: Indicative Floating Foundation Options for the Array

Table 4.3: Maximum Design Envelope: Floating Foundations

                        Mooring systems

74. The floating foundations are connected to the seabed via mooring and anchoring systems. Mooring lines run from the floating foundations, through the water column, to an anchoring system which maintains station of the floating foundation. The mooring line will connect to the floating foundation at a point below the splash zone, nominally set at 5 m below the sea surface. The point at which the mooring line reaches the seabed is referred to as the touchdown point.
75. Four mooring system options are currently being considered within the PDE, namely:

• catenary - catenary mooring lines typically comprise free hanging chains, secured to the seabed using anchors. Some designs may include the addition of clump weights to enhance the stiffness and restoring capacity.;
• semi taut - semi taut mooring lines typically use mixed materials, for example, chain and synthetic rope, secured to the seabed with anchors. Ancillary components like buoyancy modules may be required to achieve desired configuration.;
• taut - taut mooring lines use mostly synthetic ropes connected to small sections of chain at the seabed and at the top section, to prevent abrasion damage to the fibre ropes. Taut mooring lines are usually kept under tension and have a narrower mooring footprint; and
• tendons - tendons may also be used, which are tensioned mooring lines running vertically from the floating foundation to the seabed, and are only applicable for use with TLP floating foundations.

76. For catenary and semi-taut mooring systems sections of the mooring lines will lie on the seabed. During normal operations systems will be designed to minimise the excursion of floating foundations as far as practicable. However, during stronger winds and heavy sea states when floating foundations move to the edge of the excursion limits mooring lines on the windward side of the turbine will experience increased tension and may lift from the seabed. Mooring lines on the leeward side of the turbine would slacken and drop to the seabed ( Figure 4.5   Open ▸ ). The greatest changes would be anticipated with the catenary mooring system followed by the semi taut mooring systems. 
77. For the taut system it is anticipated that mooring lines would only interact with the seabed during extreme weather conditions. For the tendons option, mooring lines are tensioned, meaning that they run vertically from the floating foundation straight to the seabed, therefore, the mooring lines would not interact with the seabed and would not extend horizontally beyond the floating foundation footprint, unlike the catenary, semi taut and taut options ( Figure 4.6   Open ▸ , Figure 4.7   Open ▸ and Figure 4.8   Open ▸ , respectively).
78. It should be noted that the final mooring line solution selected may vary across the site, and will be dependent upon the anchoring solution chosen (see paragraph 79). A schematic of the different mooring systems is provided in Figure 4.6   Open ▸ , Figure 4.7   Open ▸ and Figure 4.8   Open ▸ , respectively .
79. The mooring system will be limited to a maximum of six and nine mooring lines per wind turbine for the 130 and 265 turbine scenarios respectively. Mooring line radius is not expected to exceed 700 m, and maximum length of mooring line per foundation will be up to 750 m. A maximum of 680 m of mooring line per foundation will rest on the seabed during normal operations. The maximum design envelope for the mooring system options is presented in Table 4.4   Open ▸ .

Figure 4.5: Indicative Schematic of Example Semi-Submersible Floating Foundation with Catenary Mooring System Option During Normal Operations and Extreme Conditions

Figure 4.6: Indicative Schematic of Catenary Mooring System Option for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Figure 4.7: Indicative Schematic of Taut Mooring System Options for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Figure 4.8: Indicative Schematic of Taut Mooring System Options for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Table 4.4: Maximum Design Envelope: Mooring Systems

                        Anchoring systems

80. Anchoring systems fix the mooring lines to the seabed and may include various solutions, such as driven piles, or embedded anchor types such as suction anchors and Drag Embedment Anchors (DEA). A brief description of the various anchoring types that are considered are presented in Table 4.5   Open ▸ .

Table 4.5: Description of Anchoring Options Considered in the Maximum Design Envelope

81. The Applicant is considering installation of up to nine anchors per floating foundation within the PDE. The final anchoring solution selected may vary across the site and will take account of the seabed conditions, detailed analysis of geotechnical data to inform engineering design, and environmental impacts. A range of scenarios has been identified based on preliminary analysis of geophysical and geotechnical data to identify possible anchoring solutions arrangements which could be installed for the purposes of undertaking a robust assessment. The Applicant has undertaken preliminary geotechnical surveys to determine feasibility of the proposed scenarios.  Geotechnical samples were not taken at every turbine location; therefore, flexibility is retained within the PDE to ensure there will be feasible anchoring solutions across the site. This will be informed by detailed geotechnical surveys and engineering design to identify the most appropriate anchor technology.
82. The final design may vary from the specific scenarios outlined but the environmental impacts will be no greater than the maximum design scenario impacts resulting from these scenarios and will be confirmed post-consent within the suite of consent plans. The scenarios assessed within this RIAA are as follows:

• Anchoring Option 1 - use of driven piles to anchor all floating foundations;
• Anchoring Option 2 - use of DEAs to anchor all floating foundations;
• Anchoring Option 3 – use of a mix of driven piles and DEAs to anchor up to 65% and 35% of the floating foundations, respectively;
• Anchoring Option 4 – use of a mix of driven piles and suction anchors to anchor up to 65% and 35% of the floating foundations, respectively; and
• Anchoring Option 5 - use of driven piles, shared between the floating foundations (equating to up to 70% of the total number of piles required for Anchoring Option 1).

83. Anchoring Option 1 is considered the most likely anchoring solution for the project at this stage, with Anchoring Options 2 to 5 considered as alternative options which may be used depending upon the results of engineering and environmental studies. A description of the maximum design envelope for each Anchoring Option is presented in Table 4.6   Open ▸ to Table 4.10   Open ▸ . Images of the anchoring solutions are presented in Figure 4.9   Open ▸ . Shared anchors will be considered by the project subject to appropriate layout design. This has the potential to reduce the overall number of anchors required within the site boundary. The maximum length of mooring line detailed within Table 4.4   Open ▸ may be exceeded for the shared anchor solution, however, the overall length of anchor chain required across the array, including length of chain on the seabed, would be reduced by utilising shared anchors.
84. Considering all Anchoring Options, the maximum seabed footprint per foundation is 900 m2 and maximum seabed footprint for the Array is 159,000 m2. Scour protection may be required for the anchoring systems with up to 8,511 m2 of scour protection to be installed per foundation, and up to 1,503,612 m2 of scour protection to be installed across the Array.

Table 4.6: Maximum Design Envelope: Anchoring Option 1

Table 4.7: Maximum Design Envelope: Anchoring Option 2

Table 4.8: Maximum Design Envelope: Anchoring Option 3

Table 4.9: Maximum Design Envelope: Anchoring Option 4

Table 4.10: Maximum Design Envelope: Anchoring Option 5

Figure 4.9: Schematic of Anchoring Options

                        Emerging anchor technologies

85. The Applicant is engaging with a number of suppliers who are developing innovative solutions to address some of the challenges associated with anchoring of floating offshore wind turbines. A number of emerging anchoring technologies are being considered by the Applicant.
86. These anchor technologies have the potential to increase efficiency by using less materials to achieve similar or higher loading capacities, reduce installation times and transportation requirements, mitigate supply chain constraints and further mitigate environmental effects. Innovative solutions currently being considered include using helical micro piles to fix an anchor plate to the seabed. These include helical piles that are installed through a bespoke installation tool, or drilled and grouted micro piles installed using a drilling template.
87. The Applicant will aim to use these technologies where they are feasible (depending on availability, certification, ground conditions and design performance) and where there are opportunities to reduce environmental impacts. These technologies will be presented in post-consent plans outlining how the construction and deployment falls within parameters assessed within the RIAA.

                        Connectors and ancillaries

88. The use of a number of different connectors and ancillaries may be required for the mooring and anchoring systems which alter the mooring system behaviour, for example, to reduce dynamic loads, and to reduce mooring line radius which limits movement of the floating foundation. The following connectors and ancillaries may be used:

• Long Term Mooring (LTM) connectors (shackles or H-links): these are used to securely connect different mooring line sections and the mooring lines to the anchoring systems.
• Clump weights: these may be added near the touchdown point of the mooring line to reduce the mooring line radius and provide additional weight. These are commonly used with catenary mooring lines and are usually installed over the chain links.
• Buoys or buoyancy elements: commonly used with semi taut mooring lines, these are used to suspend portions of the mooring line within the water column. The depth of these buoyancy elements within the water column can be altered, which allows the correct tension to be obtained.
• In-line tensioners: these may be added to the mooring line in order to install mooring lines with the correct tension.

89. The maximum design envelope for mooring line connectors and ancillaries is presented in Table 4.11   Open ▸ and a schematic is presented in Figure 4.10   Open ▸ and Figure 4.11   Open ▸ .

Table 4.11: Maximum Design Envelope: Connectors and Ancillaries

Figure 4.10: Indicative Schematic of Mooring Line Connectors and Ancillaries Showing LTM Connectors, Clump Weights, and In-Line Tensioners

Figure 4.11: Indicative Schematic of Mooring Line Connectors and Ancillaries Showing LTM Connectors and Buoyancy Modules

4.3.4. Offshore Substation Platforms

90. The OSPs will transform the electricity generated by the wind turbines to a higher voltage and/or to direct current allowing the power to be efficiently transmitted directly to shore or to a wider offshore grid network.
91. The Applicant has defined two options for OSP arrangements to be assessed within the appropriate assessment. The exact number and size of OSPs will be subject to National Grid ESO final design recommendations and detailed design, however, the overall size, footprint, piling parameters and key design features will remain within the representative OSP design scenarios considered. The following OSP arrangement scenarios have been considered:

• OSP Option 1: up to six large High Voltage Alternating Current (HVAC)/High Voltage Direct Current (HVDC) OSPs; or
• OSP Option 2: a combined option comprising:

–           up to three large HVAC/HVDC OSPs; and

–           up to 12 small HVAC OSPs.

92. The following subsections describe the maximum design envelope for the topsides and foundations for these options.

                        Offshore platform topsides

93. Up to six large OSP topsides will be installed with maximum dimensions of up to 121 m (length) by 89 m (width) and will be approximately 93 m in height (above LAT), excluding the helideck, lightning protection and antenna structure ( Table 4.12   Open ▸ ).
94. Should OSP Option 2 be selected at the final design stage, up to 12 small OSPs will be installed (alongside three large OSPs with same dimensions as mentioned previously), up to 41 m in length, 37 m in width and 50 m in height, excluding helideck, lightning protection and antenna structure ( Table 4.13   Open ▸ ). The final solution chosen, and the topside sizes, will be dependent on the final electrical set up for the Array.

Table 4.12: Maximum Design Envelope: OSP Option 1 Topsides

Table 4.13: Maximum Design Envelope: OSP Option 2 Topsides

                        Offshore platform foundations

95. The OSPs will be installed on fixed jacket foundations and will be located within the Array. For large OSPs, the fixed jacket foundations will have up to 12 legs, whereas fixed jacket foundations for small OSPs will have up to six legs. Up to two piles will be required per leg for both large and small OSPs.
96. For OSP Option 1, this results in a maximum of 24 piles required per foundation. Up to 144 piles will require piling for up to six large OSPs ( Table 4.14   Open ▸ ). For OSP Option 2, a maximum of 24 piles will be required per foundation for three large OSPs and a maximum of 12 piles will be required per foundation for 12 small OSPs, resulting in a total number of up to 216 piles requiring piling ( Table 4.15   Open ▸ ). It should be noted that diameter of piles required for large OSP fixed jacket foundations are 4.5 m, whereas small OSP fixed jacket foundations will require piles with a diameter of 3 m.
97. Table 4.14   Open ▸ and Table 4.15   Open ▸ describe the maximum design envelope for OSP Option 1 and OSP Option 2, respectively.

Table 4.14: Maximum Design Envelope: OSP Option 1 Fixed Jacket Foundations

Table 4.15: Maximum Design Envelope: OSP Option 2 Fixed Jacket Foundations

4.3.5. Scour Protection for Foundations

98. Natural hydrodynamic and sedimentary processes can lead to seabed erosion and ‘scour hole’ formation around anchor and mooring systems, and foundation structures. Scour hole development is influenced by the shape of the foundation structure, seabed sedimentology and site-specific metocean conditions such as waves, currents, and storms. Employing scour protection can mitigate scour around foundations. Commonly used scour protection types include:

• concrete mattresses: cast of articulated concrete blocks, several metres wide and long and linked by a polypropylene rope lattice, which are placed on and/or around structures to stabilise the seabed and inhibit erosion; or
• rock: the most frequently used scour protection method. Layers of graded stones placed on and/or around structures (e.g. foundation structures) to inhibit erosion, or rock filled mesh fibre bags which adapt to the shape of the seabed/structure as they are lowered on to it.

99. The type and volume of scour protection required will vary depending on the various wind turbine anchoring options and offshore platform options considered, and the final parameters will be decided once the design of these is finalised. This decision will consider a range of aspects including geotechnical data, meteorological and oceanographical data, water depth, foundation type, maintenance strategy, and cost.
100. Table 4.16   Open ▸ presents the maximum design envelope for scour protection required for the Anchoring Options described in section 4.3.3. It should be noted that Anchoring Option 2 is not included within Table 4.16   Open ▸ as there is no requirement for scour protection for this option. DEAs are fully embedded within the seabed (see Table 4.5   Open ▸ ) and, therefore, erosion around the structure is unlikely to occur, minimising the need for scour protection.
101. Table 4.17   Open ▸ presents the maximum design envelope for the OSP Options described in section 4.3.4.

Table 4.16: Maximum Design Envelope: Scour Protection for Anchoring Options[7]

Table 4.17: Maximum Design Envelope: Scour Protection for OSP Options

4.3.6. Subsea Cables

                        Inter-array cables

102. Inter-array cables carry the electrical current produced by wind turbines to an OSP. So as not to hinder the movement of the floating foundations, it is proposed that dynamic inter-array cables will be used. There are several cable designs which may be used, however, the most likely to be used for the Array is a ‘lazy-S’ configuration which allows extension of the cables in response to the floating foundation movements. Buoyancy modules are attached to the dynamic inter-array cable to support the weight of the cable and provide the ‘lazy-S’ configuration in the water column (as demonstrated in Figure 4.12   Open ▸ ). Bend stiffeners help to reduce the fatigue in the inter-array cables and are typically used where the cable exits the floating foundation and at touch down points of the cable on the seabed.
103. Where the dynamic cable transitions to static, the transition length (dynamic touch down) would typically have protection around the cable to protect the cable from abrasion and fatigue. Tether clamps and anchor may also be required ( Figure 4.12   Open ▸ ) to limit the movement at the touch down area. A tether clamp is designed to secure subsea lines to an anchor on the seabed and usually comprises a steel housing that is bolted over the cable with a padeye to secure a chain to a weighted anchor on the seabed. Where the static cable is laid on the seabed it will be protected in line with the outputs of the Cable Burial Risk Assessment (CBRA). It is anticipated that cable burial methods will be used to protect cables, with external cable protection employed where target burial depths cannot be achieved. A schematic of the dynamic/static inter-array cabling system is presented in Figure 4.12   Open ▸ .

Figure 4.12: Typical Indicative Schematic of the Dynamic/Static Inter-array Cable System (Subject to Detailed Design Configuration)

104. Different approaches and techniques are available for burial of the inter-array cables laid on the seabed. The final choice of burial or external cable protection methods will be subject to a review of the seabed conditions and the CBRA. Equipment which will be used to achieve cable burial is described in paragraph 154.
105. External cable protection methods will be required in areas where cable burial is unachievable, for example, where there are pre-existing cables or pipelines, or areas of exposed bedrock. A hard protective layer, such as rock or concrete mattresses, may be used to protect exposed cables. The need for this additional external protection will be subject to whether minimum target cable burial depths recommended for protection from the external threats can be achieved. Factors such as seabed conditions and sedimentology, naturally occurring physical processes and any potential interactions with human activities such as vessel anchoring and bottom-trawl fishing gear, will influence the requirement for additional protection. Site preparation activities may be required to provide relatively flat seabed surface for installation of cables and enable burial of inter-array cables to target burial depths.
106. The cable burial methodology and potential external cable protection will be identified at the final design stage (post-consent). The maximum design envelope for the inter-array cables is presented in Table 4.18   Open ▸ . Figure 4.13   Open ▸ presents a schematic of the dimensional characteristics set out in Table 4.18   Open ▸ .

Table 4.18: Maximum Design Envelope: Inter-Array Cables

Figure 4.13: Indicative Inter-Array Cable Dimensional Characteristics