2.             Proposed Development Description

2.1.        Introduction

77. This section of the Offshore EIA Scoping Report provides an outline description of the Proposed Development and describes activities associated with the construction, operation and maintenance, and decommissioning of the Proposed Development. It summarises the design and components for the Proposed Development infrastructure, based on conceptual design information and refinement of the Proposed Development parameters following receipt of the Offshore EIA Scoping Opinion for the initial Berwick Bank Wind Farm proposal, and understanding of the environment from survey work and desk-top analysis.

2.2.        Design Envelope Approach

78. The Project Design Envelope (PDE) approach (also known as the Rochdale Envelope approach) will be adopted for the assessment of the Proposed Development, in accordance with current good practice and the “Rochdale Envelope Principle”[1]. The PDE concept allows for some flexibility in project design options, particularly for foundations and wind turbine type, where the full details of a project are not known at application submission.
79. The use of the Design Envelope approach has also been recognised in the UK Overarching National Policy Statement (NPS) for Energy (NPS EN-1) (DECC, 2011a) and the NPS for Renewable Energy Infrastructure (NPS EN-3) (DECC, 2011b). This approach has been used in the majority of offshore wind farm applications in the UK to date. NPS states that ‘although the IPC (infra planning committee) will not examine projects in Scottish waters - energy policy is generally a matter reserved to UK Ministers and this NPS may therefore be a relevant consideration in planning decisions in Scotland.’
80. In the case of offshore wind farms, NPS EN-3 (paragraph 2.6.42) recognises that: “Owing to the complex nature of offshore wind farm development, many of the details of a proposed scheme may be unknown to the applicant at the time of the application, possibly including:

• precise location and configuration of wind turbines and associated development;
• foundation type;
• exact wind turbine tip height;
• cable type and cable route; and
• exact locations of offshore and/or onshore substations.”
  81. An example of the Design Envelope approach would be where several types of wind turbine foundation are being considered, then the assessment is based on the foundation known to have the greatest impact (the maximum adverse impact). In this instance, the Design Envelope for the foundation with the greatest seabed disturbance potential would be the foundation with the largest footprint and the greatest number of wind turbines. If, after undertaking the impact assessment, it is shown that no significant effect is anticipated, it can be assumed that any project parameters equal to or less than those assessed in the PDE will have environmental effects of the same level or less and will therefore also have no significant effect upon the receptors for the topic under consideration.
  82. Throughout this Offshore EIA Scoping Report (and subsequent Offshore EIAR), the Design Envelope approach has been undertaken to allow meaningful assessments of the Proposed Development to proceed, whilst still allowing reasonable flexibility for future project design decisions.

2.3.        Proposed Development Summary

83. The Proposed Development Array Area is located 33.5 km offshore of the East Lothian and the Scottish Borders coastline (closest point is St Abb’s Head) in Scotland and located within the former Firth of Forth Zone (Figure 1.1  Open ▸ ). The Proposed Development Array Area comprises an area of approximately 1,314 km2 overlapping the large-scale morphological banks ‘Marr Bank’ and ‘Berwick Bank’.
84. SSER is currently assessing the feasibility of two landfall locations on the East Lothian, Thorntonloch Landfall and Skateraw Landfall (Figure 3.2  Open ▸ ). One will be selected. A grid connection point has been confirmed at a new 400 kV Branxton substation, south west of Torness Power station under an existing grid connection agreement. A potential ECC has been identified (Figure 3.2  Open ▸ ). As noted earlier, SSER is also considering an additional offshore ECC, which is under development. This ECC does not form part of the Proposed Development for which this Scoping request has been made. However, it will be considered within the Cumulative Effects Assessment (CEA) for the Offshore EIA Report (and the Onshore EIA Report) as appropriate, to ensure compliance with the requirements of the EIA Regulations
85. The following sections provide the design parameters, which constitute the realistic maximum adverse design scenario for each technical assessment. The design of the Proposed Development has been developed and refined through stakeholder engagement on the initial Berwick Bank Wind Farm Proposal, and analysis of engineering, technical and environmental constraints. This Offshore EIA Scoping Report therefore presents an accurate summary of the Offshore EIAR project description for which necessary consent applications (section 36 consent and marine licences) will be sought.
86. A 35-year consent life under s.36 of the Electricity Act will be applied for.

2.3.2.    Proposed Development Boundary

87. An agreement for lease (AfL) grants rights to the respective AfL holders SSER (via its wholly owned subsidiary project companies) to carry out investigations, such as survey activities, to identify the potential design of the offshore array within the AfL areas for the wind farm by understanding environmental and technical constraints. The Proposed Development Array Area includes the majority of previous Marr Bank Wind Farm and initial Berwick Bank Wind Farm AfL areas. Site selection and consideration of Alternatives is discussed in section 3  Open ▸ .
88. The Proposed Development covers and area of 1,314 km2. This is where the offshore infrastructure, such as the wind turbines, offshore substation(s), array cables, and the start of the proposed ECC will be located and is hereafter referred to as the ‘Proposed Development Array Area’ throughout the Offshore EIA Scoping Report. The proposed ECC has been identified and will connect the Proposed Development Array Area to Thorntonloch Landfall or Skateraw Landfall.
89. The Proposed Development boundary is illustrated within Figure 1.1  Open ▸ . This area encompasses the:

• Proposed Development Array Area: This is where the offshore wind farm will be located, which will include the wind turbines, wind turbine foundations, array cables, and a range of offshore substations and offshore interconnector cables; and
• ECC: This is where the offshore electrical infrastructure such as the offshore export cable(s) will be located.

2.3.3.    Water Depths and Seabed within the Agreement for Lease Area

90. 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. These two bank features are defined as Shelf Banks and Mounds and are part of the Firth of Forth Banks Complex.
91. The maximum recorded 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 Proposed Development Offshore Wind Farm Proposed Development Array Areas (32.8 m LAT). The average seabed depth across the Proposed Development Array Area is 51 m below LAT.
92. The seafloor morphology is very varied and can be classified into four types of morphological features:

• two large scale banks;
• arcuate ridges;
• incised valleys, relic glacial lakes and channels; and
• bedforms.
  93. Seabed sediments within the Proposed Development Array Area are classified into several groups including coarse shelly cobbly gravel or shelly gravelly sand, gravelly sand, mixed sediment, including clay and sand. Further details of the bathymetry and seabed composition are presented within Appendix 5  Open .

2.3.4.    Offshore Proposed Development Infrastructure Overview

The key offshore components of the Proposed Development are likely to 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 OSPs and associated support structures and foundations;
• estimated scour protection of 2 km2;
• network of inter-array cabling linking the individual wind turbines to OSPs, end links plus inter-connections between substations (approximately 1,225 km of array cabling and 94 km of interconnector cabling); and
• up to twelve offshore export cables connecting the offshore substation(s) to the onshore substation.

2.3.5.    Wind Turbines

94. The Proposed Development will be comprised of up to 307 wind turbines, and the final number of wind turbines will be dependent on the capacity of individual wind turbines used and also environmental and engineering survey results. There is the potential for a reduced number of wind turbines to be used if an increased rated output of wind turbine model is chosen when the final project design is developed.
95. The maximum rotor blade diameter is expected to be no greater than 310 m, with a maximum blade tip height of 355 m above LAT and a minimum blade tip height of 37 m above LAT. The top of the wind turbine (the nacelle) will be maximum of 200 m above LAT. A scheme for wind turbine lighting and navigation marking will be agreed with consultees post-Application.
96. The layout of the wind turbines will be developed to best utilise both the available wind resource and suitability of seabed conditions, while ensuring environmental effects and impacts on other marine users (such as fisheries and shipping routes) are minimised. The final layout of the wind turbines will be confirmed at the final design stage (post-application).
97. A schematic of a typical offshore wind turbine is illustrated within Figure 2.1  Open ▸ , and the design envelope for wind turbines is presented in Table 2.1  Open ▸ .

Table 2.1: Design Envelope: Wind Turbines

Figure 2.1
: Schematic of an Offshore Wind Turbine

2.3.6.    Wind Turbine Foundations and Support Structures

98. To allow for flexibility in foundation choice, two wind turbine support structures and foundations are being considered for the Proposed Development – piled jacket and suction caisson jacket.
99. There is the potential for seabed preparation to be required for each foundation type, which may include seabed levelling and removing surface and subsurface debris such as (for example) boulders, fishing nets, unexploded ordnance, or lost anchors. Excavation may be required to access and remove any debris which is present below the seabed surface.
100. Foundations will be fabricated offsite, stored at a suitable port facility (if required) and transported to site as needed. Specialist vessels will transport and install foundations. Scour protection (typically rock) may be required on the seabed and will be installed either 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 are discussed in section 2.3.8.

Piled Jacket Foundation

101. 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 2.2  Open ▸ ). The hollow steel pin piles are typically driven, drilled or vibrated into the seabed relying on the frictional and end bearing properties of the seabed for support. The jacket structure is installed prior to the installation of the tower. There is no separate transition piece (TP), the TP and ancillary structure are fabricated as an integrated part of the jacket structure and is not installed separately offshore. The design envelope for jacket foundations with pin piles is provided in Table 2.2  Open ▸ .

Figure 2.2:  Schematic of a Jacket Foundation with Pin Piles

Table 2.2: Design Envelope: Jacket Foundation with Pin Piles

Suction Caisson Jacket Foundations

102. 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 2.3  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. As with the piled jacket foundations, there is no separate TP. The jacket structure is installed prior to the installation of the tower.
103. The foundations will be transported to site via 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 design envelope for jacket foundations with suction caissons is provided in Table 2.3  Open ▸ .

Figure 2.3:  Schematic of a Jacket Foundation with Suction caissons

Table 2.3: Design Envelope: Suction caisson Jacket Foundations

2.3.7.    Scour Protection for Foundations

104. 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, such as:

• 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: 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.
  105. The most frequently used scour protection method is ‘rock placement’, which entails the placement of crushed rock around the base of the foundation structure.
  106. The amount of scour protection required will vary for the different 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.

2.3.8.    Offshore Platforms

107. The Proposed Development may require up to a total of ten offshore platforms. These offshore platforms will be utilised as OSPs which transform electricity generated by the wind turbines to a higher voltage and thereby allowing the power to be efficiently transmitted to shore. The platform topsides size will depend on the final electrical set up for the wind farm but could range between approximately 35 – 100 m (length) by 27 – 80 m (width), and approximately 45 – 80 m in height (above LAT), excluding the helideck or lightning protection (Table 2.4  Open ▸ ). The Project Description in the Offshore EIAR will provide further detail on the design of offshore platform and topside specification.

Table 2.4: Design Envelope: Offshore Platforms

108. The platforms locations have not yet been selected and will be identified through detailed design consideration. The offshore platforms will be installed with piled jacket foundations, as described in section 2.3.6. The design envelope for jacket foundations with pin piles is shown in Table 2.5  Open ▸ .

Table 2.5: Design Envelope: Jacket Foundation with Pin Piles for Offshore Platforms

2.3.9.    Inter-array Cables

109. Inter-array cables carry the electrical current produced by the wind turbines to an offshore substation. A small number of wind turbines will typically be grouped together on the same cable ‘string’ connecting those wind turbines to the substation, and multiple cable ‘strings’ will connect back to each offshore substation.
110. The inter-array cables will be buried where possible and protected with a hard-protective layer (such as rock or concrete mattresses) where burial is not achievable, for example where crossing pre-existing cables, pipelines or exposed bedrock. If cable protection is required, the protection measure will be dependent on several factors such as seabed conditions, seabed sedimentology and the physical processes. The cable installation methodology and potential cable protection measures will be finalised at the final design stage (post-application). The design envelope for inter-array cables is presented in Table 2.6  Open ▸ .

Table 2.6: Design Envelope: Inter-Array Cables

2.3.10.                        Offshore Transmission Infrastructure

111. Offshore export cables are used for the transfer of power from the offshore substations to the point of landfall. The offshore export cables will have a maximum total length of 1,072 km, comprised of up to twelve cables. Each of these export cables will be installed in a trench up to 2 m wide with a burial depth of between 0.5 m and 3 m per cable. There is the potential for seabed preparation to be required prior to cable installation, with methods such as jet trencher, mechanic trencher or grapnel currently being considered.
112. Although an ECC has been identified, the exact locations of the offshore export cables are 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 export cables to ensure physical and technical constraints, changes in available technology and project economics can be accommodated within the final design.
113. Likewise, SSER is currently considering the feasibility of two landlfall locations as part of the Proposed Development: Skateraw and Thorntonloch. One will be selected. The installation of the export cables through the intertidal zone at the Skateraw or Thorntonloch landfalls will depend on pre-construction confirmation of ground conditions however one of the following methods of installation will be implemented and the EIA Report will consider either:

• trenchless installation: installation of the offshore export cable via trenchless installation methods such as Horizontal Directional Drilling (HDD) or Direct Pipe®; or
• open cut trench: this method involves the excavation of a trench on the shore via earth moving equipment. The cable is then pulled ashore into the trench and the trench is backfilled and then re-instated.
  114. If the cables at landfall are installed using a trenchless technique, designed in measures will avoid exposure.
  115. The design envelope for the offshore transmission infrastructure forming part of the Proposed Development is described in Table 2.7  Open ▸ .

Table 2.7: Design Envelope: Offshore Transmission Infrastructure

2.4.        Offshore Construction Phase

116. The Proposed Development is likely to be constructed over a period of four years in line with the general construction series outlined below:

1. pre-construction surveys and activities (including UXO clearance, geophysical and geotechnical surveys);
2. foundation installation;
3. OSP installation/commissioning;
4. inter-array cable installation;
5. offshore export cable; and
6. wind turbine installation/commissioning.
   117. The offshore construction phase will be supported by various vessels including jack-up or floating Heavy Lift vessels (HLV), support vessels, cable lay vessels, pre-lay survey vessels, Remotely Operated underwater Vehicle (ROV) deployment vessel, rock installation vessel, service and commissioning support vessels, and guard vessels.
   118. Wind turbines, foundation structures and offshore platform structures will be transported from the pre-assembly harbour where sub-assemblies (nacelle, rotor blades and towers) will be loaded onto an installation vessel or support vessel. At the installation location, the wind turbine tower will be erected first, followed by the nacelle and blades. The blades may be installed one at a time or may be pre-assembled. Following installation of the wind turbine and connection to the necessary cabling, a process of testing and commissioning will be undertaken.

2.5.        Operation and Maintenance Phase

119. Operations and maintenance works will be conducted from either a Service Operations Vessel (SOV), helicopter, drones or Crew Transfer Vessel (CTV) for routine operations and maintenance works, as well as heavy lift vessels and/or jack-up vessels for infrequent major maintenance campaigns. The details of estimated annual and total operations and maintenance activities will be detailed within the Design Envelope of the Offshore EIAR.

2.6.        Decommissioning Phase

120. Under Section 105 of the Energy Act 2004 (as amended), developers of offshore renewable energy projects are required to prepare a decommissioning programme for approval by Scottish Ministers. A Section 105 notice is issued to developers by the regulator after consent or marine licence has been issued for the given development. Developers are then required to submit a detailed plan for the decommissioning works, including anticipated costs and financial securities. The plan will consider good industry practice, guidance and legislation relating to decommissioning at that time. The plan will be consulted on by an approved set of stakeholders and will be publicly available. Marine Scotland Licensing Operations Team (MS-LOT) will further consult on the plan, the costs and financial securities prior to seeking ministerial approval.
121. The Offshore EIAR will provide an overview of the anticipated decommissioning events and an assessment of the potential significant effects of this phase on receptors.
122. The initial Berwick Bank Wind Farm Proposal Offshore EIA Scoping Opinion (Scottish Government, 2021) requested an assessment of decommissioning which is “as close to full removal at decommissioning as possible”. SSER intend to assess a decommissioning scenario close to full removal that will ensure that a good practice approach is followed at the time of decommissioning.

2.7.        Designed in Measures

123. The following designed in measures will be included within the Proposed Development project design, and will be considered in assessment in the Offshore EIAR. These are summarised in Appendix 2  Open :

• scour protection: The use of scour protection around offshore structures and foundations will be employed,
• suitable implementation and monitoring of cable protection through the Operation and Maintenance phase of the Proposed Development;
• development and adherence to a Cable Plan (CaP).;
• core working hours for the construction of the onshore elements of the Proposed Development will be Monday to Sunday 07.00 to 19.00 hour. Activities carried out during mobilisation and maintenance will not generate significant noise levels (such as piling, or other such noisy activities). In certain circumstances, specific works may have to be undertaken outside the normal working hours;
• where airborne noise has the potential to cause disturbance the use of mufflers, acoustic barriers and screening will be considered. The construction and decommissioning works would use Best Practicable Means (BPM) to limit the impacts of noise at sensitive receptors. Those measures would be set out in the Construction Environmental Management Plan (CEMP). Monitoring of noise related complaints should also be undertaken.
• development of, and adherence to, an appropriate Code of Construction Practice (CoCP);
• the dust and air quality management plan within the CoCP will include good practice measures in accordance with the Institute of Air Quality Management (IAQM);
• the development of, and adherence to, an Environmental Management Plan, including Marine Pollution Contingency Plan and Invasive Non-Native Species (INNS) Management Plan;
• development of, and adherence to, a Decommissioning Plan;
• implementation of piling soft-start and ramp-up measures;
• the development of, and adherence to, a Piling Strategy (PS);
• development of, and adherence to, a Vessel Management Plan (VMP);
• use of deflagration to clear all UXOs;
• increased minimum turbine tip height (air gap) to a minimum of 37m;
• development of, and adherence to, a Marine Mammal Mitigation Protocol (MMMP - geophysical survey specific and piling specific);
• ongoing consultation with the fishing industry and appointment of a Fisheries Liaison Officer (FLO);
• development of a Fisheries Management and Mitigation Strategy (FMMS);
• adherence to good practice guidance with regards to fisheries liaison (e.g. FLOWW, 2014;2015);
• timely and efficient distribution of Notice to Mariners (NtM), Kingfisher notifications and other navigational warnings of the position and nature of works associated with the Proposed Development;
• use of guard vessels and Offshore Fisheries Liaison Officers (OFLOs), as appropriate;
• implementation Navigational Safety Plan (NSP);
• notification to the UK Hydrographic Office (UKHO) of the proposed works to facilitate the promulgation of maritime safety information and updating of nautical charts and publications;
• undertaking of post-lay and cable burial inspection surveys and monitoring,
• participation in the Forth and Tay Commercial Fisheries Working Group (FTCFWG) and liaison with Fisheries Industry Representatives (FIRs), as appropriate.
• compliance with MGN 654 and its annexes (in particular Search and Rescue (SAR) annex 5 (MCA, 2021) and completion of a SAR checklist) where applicable;
• buoyed construction area in agreement with NLB;
• application for safety zones of up to 500 m during construction and periods of major maintenance;
• marine coordination and communication to manage project vessel movements;
• suitable implementation and monitoring of cable protection (via burial, or external protection where adequate burial depth as identified via risk assessment is not feasible);
• marking and lighting of the site in agreement with NLB and in line with IALA Recommendation O-139 (IALA, 2013);
• compliance of all vessels with international marine regulations as adopted by the Flag State, notably the International Regulations for Preventing Collisions at Sea (COLREGs) (IMO, 1974) and the International Convention for the Safety of Life at Sea (SOLAS) (IMO, 1974);
• blade clearance of at least 37 m above MHWS (in line with RYA policy (RYA, 2015));
• Adherence Civil Aviation Publication (CAP) 393 Article 223 (Civil Aviation Authority (CAA), 2018
• Implementation of a Lighting and Marking Plan (LMP) which will set out specific requirements in terms of aviation lighting to be installed on the wind turbines.
• all structures > 91.4 m in height will be charted on aeronautical charts and reported to the Defence Geographic Centre (DGC) which maintains the UKs database of tall structures (Digital Vertical Obstruction File) at least ten weeks prior to construction.
• use of advisory safety distances around vessels undertaking construction, major maintenance and decommissioning activities;
• crossing or laying of cables over or adjacent to known or future cables will be subject to crossing and/or proximity agreements.
• the use of locally manufactured content where possible and appropriate.
• the use of local contractors (where possible) during construction for onshore infrastructure and potential offshore construction work where possible and appropriate.
• employment and training possibilities for local people on the operation and maintenance of a wind farm where feasible; and
• supporting the community through sponsorship of local groups and teams.