2. Project Description

2.
Project Description

2.1. Introduction

  1. This section of this Scoping Report outlines a description of the Array infrastructure and describes activities associated with the construction, operation and maintenance, and decommissioning phases of the Array. The design and components for the Array infrastructure are summarised here and have been developed based upon the latest design information and current understanding of the baseline environment from survey work and desktop studies.
  2. This Scoping Report covers the following infrastructure components:
  • wind turbine generators;
  • floating foundations and associated moorings and anchoring systems;
  • Offshore Substation Platforms (OSPs);
  • fixed bottom or floating foundations for the OSPs;
  • inter-array cables connecting the turbines to the OSPs;
  • interconnector cables connecting the OSPs to each other; and
  • scour protection and cable protection.
  1. The Proposed offshore export cable corridor(s) and Proposed onshore export cable(s) (including the onshore substation at the Proposed landfall location(s)) will be subject to a separate Environmental Impact Assessment (EIA) Scoping Report(s), EIA Report(s) and consent application(s) in the future.

2.2. Design Envelope Approach

  1. The assessment of the Array will utilise the Project Design Envelope (PDE) approach (also known as the Rochdale Envelope approach), in accordance with current good practice, the “Rochdale Envelope Principle” [1], Scottish Government (2013) guidance, and guidance prepared by Marine Scotland and the Energy Consents Unit (Scottish Government, 2022l). The PDE concept will allow for sufficient flexibility in the final project design options, where the full details of a project are not known at the point of application submission.
  2. A “maximum design scenario” (MDS) approach is applied in the PDE concept, which considers a realistic range of project design parameters. For each impact pathway, the MDS will be developed from the PDE which will establish the parameters (or combination of parameters) that could result in the maximum effect (i.e. the maximum adverse scenario).
  3. The PDE approach could be used, for example, where several types of foundation mooring and anchoring systems are being considered. The assessment carried out in the Array EIA Report would be based upon the mooring and anchoring system known to have the greatest potential for impact (the realistic maximum adverse impact) to a particular receptor. In this example, the PDE for the mooring and anchoring system with the greatest potential for seabed disturbance would be the mooring and anchoring system with the largest footprint and the greatest number of wind turbines. If it is shown that no significant effect is anticipated after undertaking the impact               assessment for this scenario, it can then be predicted that any project parameters which are equal to or less than those assessed in the PDE will have the same level of, or less, environmental effects than the project parameters assessed. 
  4. The PDE approach will be applied throughout the EIA process to allow assessment of the potential impact of the Array to proceed, whilst still allowing for a level of flexibility where required for future project design decisions and advancements in technology.
  5. As the project progresses and a greater understanding of the Array is developed, the design envelope will be further refined up to design freeze. 
  6. Since the pre-Scoping workshops held by the Applicant in November 2022, some of the project design parameters presented in the workshop have changed. For clarity, Table 2.1   Open ▸ shows the parameters presented in the pre-Scoping workshops versus what is presented in this Scoping Report. The updated turbine parameters have been incorporated to account for the current commercially available technology and anticipated available technology during the latter stages of construction.

 

Table 2.1:
Changes to Maximum Design Envelope Since Pre-Scoping Workshops in November 2022

Table 2.1: Changes to Maximum Design Envelope Since Pre-Scoping Workshops in November 2022

 

2.3. Array Summary

  1. The PDE for the Array has been developed and refined through analysis of engineering, technical and environmental constraints and, therefore, provides an accurate summary of the Array EIA Report project description for which the Applicant is seeking necessary consent applications (Section 36 consent and marine licence(s)). Further development and refinement of the PDE will be undertaken throughout the EIA process as baseline data is collected and potential impacts are assessed. A 50-year consent life will be applied for.

2.3.1. Array

  1. The Array is located within the site boundary, which is located off the east coast of Scotland, approximately 80 km south-east of Aberdeen from the nearest point, and comprises an area of approximately 859 km2 (section 1,   Figure 1.1   Open ▸ ).
  2. 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.
  3. The CES Option to Lease Agreement grants rights to the Applicant to carry out investigations within the site boundary, such as survey activities, to identify the potential design of the Array within the site boundary by understanding environmental and technical constraints.
  4. See section 1.2, Figure 1.1   Open ▸ for an illustration of the site boundary.

2.3.2. Water Depths and Seabed within the site boundary

  1. A geophysical survey was conducted over the site boundary between March and July 2022 to collect geophysical and bathymetric data. The seafloor across the site boundary slopes gently downwards in an approximately north-west to south-east direction. The seafloor 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, 2022a; Appendix 7).
  2. Across the site boundary, the maximum water depth was recorded at 88.7 m Lowest Astronomical Tide (LAT), and the shallowest area was recorded at 63.8 m LAT (Ocean Infinity, 2022a; Appendix 7).
  3. 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 (EUSeaMap, 2021). The geophysical survey indicated that the seabed comprises mainly of sand, with areas of gravel in the west of the site boundary (Ocean Infinity, 2022a; Appendix 7).
  4. Further details of the bathymetry and seabed composition are presented within Appendix 5 and Appendix 7.

2.3.3. Array Infrastructure Overview

  1. The main components of the Array are expected to include:
  • up to 270 wind turbines (each comprising a tower section, nacelle, hub and three rotor blades) and associated floating support structures and foundations;
  • up to six OSPs with fixed foundations or associated floating support structures and foundations;
  • mooring and anchoring systems for each floating substructure, including anchors or piles for each mooring line;
  • a network of dynamic/static inter-array cabling linking the individual wind turbines to OSPs, and interconnector cables between OSPs (totalling approximately 1,515 km); and
  • ancillary elements including scour protection and clump weights.

2.3.4. Wind Turbines

  1. The Array will comprise up to 270 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. If an increased rated output of wind turbine model is chosen when the final project design is developed, a reduced number of wind turbines may be installed.
  2. The maximum rotor blade diameter is expected to be up to 350 m, with a maximum blade tip height of up to 399 m above LAT. The lower blade tip height will be confirmed following ongoing engineering design work and taking into account preliminary environmental assessments to mitigate effects where appropriate, but will be greater than 22 m, in accordance with Marine Guidance Note (MGN) 654 (Maritime and Coastguard Agency (MCA), 2021). The hub height will be up to 224 m above LAT. The Applicant will develop and agree a scheme for wind turbine lighting and navigation marking with consultees post-consent decision. A schematic of a typical floating wind turbine is presented in Figure 2.1   Open ▸ .
  3. The layout of the wind turbines will be developed to effectively make use of the available wind resource and suitability of seabed conditions, as well as ensuring that the environmental effects and impacts on other marine users (e.g. fisheries and shipping routes) are kept to a minimum. Confirmation of the final layout of the wind turbines will occur at the final design stage (post-consent) and in consultation with relevant stakeholders.
  4. The design envelope for wind turbines is presented in Table 2.2   Open ▸ .

 

Table 2.2:
Maximum Design Envelope: Wind Turbines

Table 2.2: Maximum Design Envelope: Wind Turbines

Figure 2.1:
Schematic of a Typical Floating Wind Turbine

Figure 2.1: Schematic of a Typical Floating Wind Turbine

 

2.3.5. Wind Turbine Foundations and Support Structures

  1. The Array will comprise wind turbines supported by floating substructures which require mooring and anchoring systems to maintain station. The substructures will be fixed to the seabed with up to nine mooring lines per foundation and anchored to the seabed via one or a combination of the anchoring types detailed in Table 2.4   Open ▸ .
  2. An overview of the typical floating substructure options is provided in Figure 2.2   Open ▸ . Each floating technology has varying dimensions as a result of the differing approach to meeting the unique engineering challenges associated with floating turbines, turbine sizes and project specific requirements. The final substructure design may look different those pictured but will follow the same design principles. The following floating substructure solutions are being considered:
  • Semi-submersible: A buoyancy stabilised platform which floats semi-submerged on the surface of the ocean 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 structure and turbine are countered/dampened by the equivalent buoyancy force on the opposite side of the structure.
  • Tension Leg Platform (TLP): A TLP is a semi-submerged buoyant structure, anchored to the seabed with tensioned mooring lines. 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 structure itself) allows for a smaller and lighter floating structure.

Figure 2.2:
Floating Substructure Options for the Array

Figure 2.2: Floating Substructure Options for the Array

 

  1. Three mooring configurations are currently being considered, namely; catenary, semi taut and taut mooring lines, as presented in Table 2.4   Open ▸ . Semi taut mooring lines typically use mixed materials, for example, chain and synthetic rope, secured to the seabed with anchors and ancillary elements, as well as buoyancy modules which lift connections off the seabed. Taut mooring line systems use synthetic or steel wire rope lines fixed to the seabed which are under tension. Anchors for this type of mooring system must be capable of withstanding vertical lift, for example, Vertical Loading Anchors (VLAs) (ORE Catapult, 2021). Catenary mooring line systems typically comprise free hanging chains, secured to the seabed using anchors and ancillary elements and may be used where the other mooring solutions are not feasible. A schematic of the differing mooring systems is provided in Figure 2.3   Open ▸ .

Figure 2.3:
Schematic of Mooring System Options for Floating Wind Turbines

Figure 2.3: Schematic of Mooring System Options for Floating Wind Turbines

 

  1. Anchoring types considered include driven piles, and a number of different embedded anchor types, including suction piles, Drag Embedment Anchors (DEA) and VLA ( Table 2.4   Open ▸ ), with up to nine anchors required per foundation. A brief description of the various anchoring types that will be considered are presented in Table 2.3   Open ▸ . Images of the anchoring solutions are presented in Figure 2.4   Open ▸ .

 

Table 2.3:
Description of Anchoring Options Considered in the Maximum Design Envelope

Table 2.3: Description of Anchoring Options Considered in the Maximum Design Envelope

Figure 2.4:
Schematic of Anchoring Options Under Consideration as Part of the Proposed Mooring Configurations (Images Courtesy of Intermoor)

Figure 2.4: Schematic of Anchoring Options Under Consideration as Part of the Proposed Mooring Configurations (Images Courtesy of Intermoor)

 

  1. It should be noted that use of driven piles will only be undertaken where other solutions are not feasible, and only  a proportion of the foundations may be piled. There may be a mix of mooring and anchoring solutions used across the Array, which would reduce the number of driven piles which may be used. Geotechnical data acquisition and further studies will be undertaken to analyse ground conditions across the site boundary and inform mooring and anchoring solutions for floating turbine substructures. Further detail on foundation parameters and anchoring will be presented within the Project Description chapter of the Array EIA Report.
  2. The mooring and anchoring systems could be connected using a number of different connectors and ancillaries which alter the mooring system behaviour, such as:
  • Long Term Mooring (LTM) connectors (shackles or H-links);
  • clump weights;
  • buoys or buoyancy elements; and
  • tensioners.
  1. Clump weights are added to mooring lines to increase initial stiffness, which reduces dynamic loads and limits the mooring radius of the floating substructure. These are generally attached as a casing around the mooring line at the touchdown point on the seabed. A schematic of mooring line connectors and ancillaries is presented in Figure 2.5   Open ▸ .

Figure 2.5:
Schematic of Mooring Line Connectors and Ancillaries

Figure 2.5: Schematic of Mooring Line Connectors and Ancillaries

 

Table 2.4:
Maximum Design Envelope: Wind Turbine Foundations, Mooring Lines and Anchors

Table 2.4: Maximum Design Envelope: Wind Turbine Foundations, Mooring Lines and Anchors

 

2.3.6. Offshore Platforms

                        OSP topsides

  1. Up to six OSPs may be required for the Array, to transform electricity generated by the wind turbines to a higher voltage allowing the power to be efficiently transmitted directly to shore or to a wider offshore grid network. As detailed in section 2.1, the infrastructure associated with the Proposed offshore export cable corridor(s) and Proposed onshore export cable corridor(s) (including the onshore substation at the Proposed landfall(s)) will be subject to a separate consent application(s). The OSP topside size will be dependent on the final electrical set up for the offshore wind farm but it is expected to be up to 130 m (length) by 110 m (width), and approximately 70 m in height (above LAT), excluding the helideck or lighting protection ( Table 2.5   Open ▸ ).
  2. Further detail on the design of the OSPs and topside specification will be presented in the Project Description chapter of the Array EIA Report.

 

Table 2.5:
Maximum Design Envelope: OSP Topsides

Table 2.5: Maximum Design Envelope: OSP Topsides

 

                        OSP foundations and support structures

  1. It is anticipated that the OSPs will be supported by fixed substructures, however, floating substructures have also  been included as an option for consideration. These are described in the sections below. Further detail of the design of the foundation and support structures for the OSPs will be provided in the Project Description chapter of the Array EIA Report.
Fixed foundations
  1. It is likely that OSPs will be installed on fixed jacket foundations. The fixed jacket foundations will have up to eight legs, with two piles required per leg.
  2. This results in a maximum of 16 piles required per foundation, with a pile diameter of approximately 4 m. Up to 96 piles will require piling for up to six OSPs ( Table 2.6   Open ▸ ).

 

Table 2.6:
Maximum Design Envelope: OSP Fixed Jacket Foundations

Table 2.6: Maximum Design Envelope: OSP Fixed Jacket Foundations

 

Floating foundations
  1. If floating foundations are used for the OSPs, the substructures will be fixed to the seabed with up to nine mooring  lines per foundation and anchored to the seabed. Three mooring line types are considered at present ( Table 2.7   Open ▸ ).
  2. Anchoring types considered include driven piles, and a number of different embedded anchor types, including suction piles, DEA and VLA ( Table 2.7   Open ▸ ), with up to nine anchors required per OSP floating foundation.
  3. Section 2.3.5 provides further details of the mooring lines and anchoring types considered. As noted in paragraph 96, the use of driven piles for floating substructures will only be undertaken where other solutions are not feasible, subject to detailed assessment. There may be a mix of mooring and anchoring solutions used across the six OSPs and/or for each OSP, which could reduce the number of driven piles which may be used. Geotechnical data acquisition and further studies will be undertaken to analyse ground conditions across the site boundary and inform mooring and anchoring solutions for floating OSPs.

 

Table 2.7:
Maximum Design Envelope: OSP Floating Foundations, Mooring Lines and Anchors

Table 2.7: Maximum Design Envelope: OSP Floating Foundations, Mooring Lines and Anchors