3.2. Array Infrastructure

3.2.1. Overview

18. 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.

19. Table 3.1   Open ▸ presents the coordinates of the Array in which the infrastructure will be located.

Table 3.1: Array Coordinates

3.2.2. Floating Wind Turbines

20. 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.
21. 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 technical assessments (volume 2, chapters 7 to 20). 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.
22. Table 3.2   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.
23. Floating wind turbines will comprise a tower section, nacelle, hub and three rotor blades, and will be attached to a floating foundation (further described in section 3.2.3). A schematic of a typical floating wind turbine is presented in Figure 3.2   Open ▸ .
24. 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.
25. 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 Marine Directorate – Licensing and Operations Team (MD-LOT) for approval. Indicative array layouts are presented in Figure 3.3   Open ▸ and Figure 3.4   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 3.2.4.

Table 3.2: Maximum Design Envelope: Floating Wind Turbines

Figure 3.2: Indicative Schematic of a Generic Floating Wind Turbine

Figure 3.3: Preliminary Array Layout Comprising up to 265 Wind Turbines and up to 15 OSP Locations

Figure 3.4: Preliminary Array Layout Comprising up to 130 Wind Turbines and up to 15 OSP Locations

26. 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.

27. 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 (DP2). An outline EMP, including an outline MPCP, is presented in volume 4, appendix 21.

3.2.3. Floating Wind Turbine Foundations and Support Structures

28. 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

29. An overview of the floating foundation options considered for the Array is provided in Figure 3.5   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 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, as described in paragraph 34.
• Tension Leg Platform (TLP): A TLP is a semi-submerged buoyant structure, anchored to the seabed with tensioned mooring lines (tendons; please see paragraph 34 for further information). 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 3.5: Indicative Floating Foundation Options for the Array

Table 3.3: Maximum Design Envelope: Floating Foundations

Mooring systems

30. 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.
31. 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.

32. 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 reduce 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 3.6   Open ▸ ). The greatest changes would be anticipated with the catenary mooring system followed by the semi-taut mooring systems.  

Figure 3.6: Indicative Schematic of Example Semi-Submersible Floating Foundation with Catenary Mooring System Option During Normal Operations and Extreme Conditions

33. 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 3.7   Open ▸ , Figure 3.8   Open ▸ and Figure 3.9   Open ▸ , respectively).
34. 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 36). A schematic of the different mooring systems is provided in Figure 3.7   Open ▸ , Figure 3.8   Open ▸ and Figure 3.9   Open ▸ , respectively.
35. The mooring system will be limited to a maximum of six and nine mooring lines per wind turbine for the 265 and 130 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 3.4   Open ▸ .

Figure 3.7: Indicative Schematic of Catenary Mooring System Option for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Figure 3.8: Indicative Schematic of a Semi-Taut Mooring System Options for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Figure 3.9: Indicative Schematic of Taut Mooring System Options for Floating Wind Turbines on Example Semi-Submersible Floating Foundation

Table 3.4: Maximum Design Envelope: Mooring Systems

Anchoring systems

36. 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 3.5   Open ▸ .

Table 3.5: Description of Anchoring Options Considered in the Maximum Design Envelope

37. The Applicant is considering installation of a maximum of six or nine anchors per floating foundation within the PDE for the 265 and 130 wind turbine scenarios respectively. 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 EIA. 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 Array. This will be informed by detailed geotechnical surveys and engineering design to identify the most appropriate anchor technology.
38. The final design may vary from the specific scenarios outlined but the environmental impacts will be no greater than the most adverse impacts resulting from these scenarios and will be confirmed post-consent within the suite of consent plans. The scenarios assessed within this Array EIA Report 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).

39. 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 3.6   Open ▸ to Table 3.10   Open ▸ . Images of the anchoring solutions are presented in Figure 3.10   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 Array. The maximum length of mooring line detailed within Table 3.4   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.
40. 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 3.6: Maximum Design Envelope: Anchoring Option 1

Table 3.7: Maximum Design Envelope: Anchoring Option 2

Table 3.8: Maximum Design Envelope: Anchoring Option 3

Table 3.9: Maximum Design Envelope: Anchoring Option 4

Table 3.10: Maximum Design Envelope: Anchoring Option 5

Figure 3.10: Schematic of Anchoring Options

                        Emerging anchor technologies

41. 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.
42. 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 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.
43. 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 Array EIA Report.

Connectors and ancillaries

44. 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 modules: 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 modules 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.

45. The maximum design envelope for mooring line connectors and ancillaries is presented in Table 3.11   Open ▸ , and  schematics are presented in Figure 3.11   Open ▸ and Figure 3.12   Open ▸ .

Table 3.11: Maximum Design Envelope: Connectors and Ancillaries

Figure 3.11: Indicative Schematic of Mooring Line Connectors and Ancillaries Showing LTM Connectors, Clump Weights and In-Line Tensioners

Figure 3.12: Indicative Schematic of Mooring Line Connectors and Ancillaries Showing LTM Connectors and Buoyancy Modules

3.2.4. Offshore Substation Platforms

46. 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.
47. The Applicant has defined two options for OSP arrangements to be considered within the Array EIA Report. The exact number and size of OSPs will be subject to National Grid (NG) Electricity System Operator Limited (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 within the Array EIA Report. The following OSP arrangement scenarios have been considered within this Array EIA Report:

• 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.

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

Offshore platform topsides

49. 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 3.12   Open ▸ ).
50. 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 3.13   Open ▸ ). The final solution chosen, and the topside sizes, will be dependent on the final electrical setup for the Array.

Table 3.12: Maximum Design Envelope: OSP Option 1 Topsides

Table 3.13: Maximum Design Envelope: OSP Option 2 Topsides

Offshore platform foundations

51. 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.
52. 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 3.14   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 3.15   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 diameter of 3 m.
53. Table 3.14   Open ▸ and Table 3.15   Open ▸ describe the maximum design envelope for OSP Option 1 and OSP Option 2, respectively.

Table 3.14: Maximum Design Envelope: OSP Option 1 Fixed Jacket Foundations

Table 3.15: Maximum Design Envelope: OSP Option 2 Fixed Jacket Foundations

3.2.5. Scour Protection for Foundations

54. 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.

55. 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.
56. Table 3.16   Open ▸ presents the maximum design envelope for scour protection required for the Anchoring Options described in section 3.2.3. It should be noted that Anchoring Option 2 is not included within Table 3.16   Open ▸ as there is no requirement for scour protection for this option. DEAs are fully embedded within the seabed (see Table 3.5   Open ▸ ) and, therefore, erosion around the structure is unlikely to occur, minimising the need for scour protection.
57. Table 3.17   Open ▸ presents the maximum design envelope for the OSP Options described in section 3.2.4.

Table 3.16: Maximum Design Envelope: Scour Protection for Anchoring Options[4]

Table 3.17: Maximum Design Envelope: Scour Protection for OSP Options

3.2.6. Subsea Cables

Inter-array cables

58. 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 3.13   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.
59. 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 weighted anchors may also be required ( Figure 3.13   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. Further detail is provided in paragraph 61. A schematic of the dynamic/static inter-array cabling system is presented in Figure 3.13   Open ▸ .

Figure 3.13: Indicative Schematic of the Dynamic/Static Inter-array Cable System (Subject to Detailed Design Configuration)

60. 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 110.
61. 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. These are discussed in section 3.3.
62. The cable burial methodology and potential external cable protection will be identified at the final design stage (post-consent). The maximum design envelope for inter-array cables is presented in Table 3.18   Open ▸ . Figure 3.14   Open ▸ presents a schematic of the dimensional characteristics set out in Table 3.18   Open ▸ .

Table 3.18: Maximum Design Envelope: Inter-Array Cables

Figure 3.14: Indicative Inter-Array Cable Dimensional Characteristics

Subsea junction boxes

63. Subsea junction boxes may be installed on the seabed which serve as a single connection point for inter-array cables from several wind turbines. There are several configurations which may be used to connect inter-array cables into the subsea junction boxes as depicted in Figure 3.15   Open ▸ . These comprise the following:

• Daisy-chain – two inter-array cables are required per wind turbine, which connect wind turbines together in sequence. The wind turbines located at either end of the grouping are connected to a single subsea junction box via the second inter-array cable exiting each of the two wind turbines. Once reaching the subsea junction box, a single static inter-array cable exits, to connect into the OSP.
• Fishbone – each wind turbine is connected to a single subsea junction box via one inter-array cable. Lengths of static inter-array cable connect the subsea junction boxes together in sequence and then a single static inter-array cable exits the final subsea junction box in the sequence to connect into the OSP.
• Star – several wind turbines are connected to a single subsea junction box via one inter-array cable per wind turbine. A single static inter-array cable exits the subsea junction box, to connect into the OSP.
• Fishbone and star hybrid – several wind turbines are connected to a single subsea junction box via one inter-array cable per wind turbine. Lengths of static inter-array cable then connect multiple subsea junction boxes together in sequence. A single static inter-array cable exits the final subsea junction box in the sequence to connect into the OSP.

Figure 3.15: Schematic of Indicative Inter-Array Cable String Configurations Utilising Junction Boxes (Subject to Detailed Design Configuration)

64. The maximum design envelope for inter-array cables, presented in Table 3.18   Open ▸ , takes into account these potential configurations and, therefore, allows flexibility in design should any of these configurations be employed alongside the subsea junction boxes.
65. The maximum design envelope for the subsea junction boxes is presented in Table 3.19   Open ▸ . At this stage, the design of the subsea junction boxes is conceptual, therefore, some parameters included are estimated; this is indicated in Table 3.19   Open ▸ as appropriate. In addition, the parameters presented in Table 3.19   Open ▸ take into account the junction boxes associated with the various inter-array cable configurations, therefore, the parameters represent a conservative estimate which is considered to be the maximum design scenario. The parameters included within the maximum design envelope for the subsea junction boxes account for ongoing development of this technology and allows flexibility in the future.

Table 3.19: Maximum Design Envelope: Subsea Junction Boxes