Chapter 5: Project Description

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CONTENTS

Page

5. PROJECT DESCRIPTION 5-1 5.1 Introduction 5-1 PTEC flexibility – The need for a device neutral approach 5-4 Project overview 5-6 Embedded mitigation 5-9 5.2 Site Description 5-12 Offshore site description 5-12 Onshore site description 5-15 5.3 Review of Existing Tidal Technologies 5-19 5.4 Tidal Energy Converter (TEC) Envelope 5-24 Axial flow TECs 5-25 Transverse axis device 5-30 5.5 Foundation System Envelope 5-33 Scour protection 5-33 Seabed mounted designs 5-34 Monopile foundation 5-41 Anchor systems 5-43 5.6 Superstructures 5-47 5.7 Array Layout and Spacing 5-50 5.8 Other Design Considerations 5-67 Corrosion protection and antifoulants 5-67 Acoustic Doppler Profilers 5-68 Lighting and markings 5-69 Liquid inventory 5-71 5.9 Offshore Electrical Infrastructure and Cabling 5-73 Tidal energy convertor electrical infrastructure 5-73 Electrical hubs 5-73 Device communication systems 5-75 Inter-array cabling 5-75 Export cabling 5-76 Cable protection / armouring 5-80 5.10 Cable Landfall 5-83 Transition pit 5-84 5.11 Onshore Infrastructure 5-86 Substation and control room 5-86 Temporary laydown/ area and possible HDD 5-86 Onshore cabling 5-86 Control room 5-101 Grid side connections 5-101 5.12 Construction Methodology 5-102 Offshore construction 5-102

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Onshore construction 5-118 5.13 Construction Schedule 5-125 Offshore construction 5-125 Onshore construction 5-126 5.14 Operation and Maintenance (O&M) 5-127 Discharges to air and water during operation 5-127 Electromagnetic fields (EMF) 5-127 Noise emissions during operation 5-127 Device and inter-array cable maintenance 5-128 Offshore export cable maintenance and inspection 5-132 Port and vessel requirements during O&M 5-133 PTEC onshore O&M requirements 5-133 Personnel requirements during O&M 5-134 Accommodation will be provided by a combination of hotels, B&Bs or rented accommodation.Onshore vehicle trips 5-134 5.15 Repowering 5-135 5.16 Decommissioning 5-137 Cables 5-137 Protection material 5-138 Tenant devices and electrical systems 5-138 Navigation buoys 5-138 Onshore substation/control room 5-139 5.17 Rochdale Envelope Summary 5-140 Offshore infrastructure summary 5-140 Landfall summary 5-144 Onshore infrastructure summary 5-144 Construction summary 5-145 O&M summary 5-148 Decommissioning summary 5-149 Summary of embedded mitigation 5-149 5.18 Conclusion 5-151

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Revision Date Author Approved Comment/ reason for issue no. by 1 16/06/14 BO, GK AD 1st draft for ITP & PTEC Ltd input 2 26/06/14 GK FF Updated with ITP comments & feedback from meeting on 23/06/14 3 14/07/14 GK FF Updated following JF & MF comments & workshop 4 02/09/14 GK AD 2nd draft for ITP & PTEC Ltd input 5 26/09/14 GK FF Draft incorporating JF, MF & JH comments 6 30/09/14 GK AD Submission to MMO, NE, LPA, EA 7 05/11/14 DT GK 3rd draft for PTEC Ltd input 8 07/11/14 GK PP Draft for TCE review 9 24/11/14 GK FF Final draft for PTEC review 10 28/11/14 GK MF Final draft

This project has been co-funded by ERDF under the INTERREG IVB NWE programme. The report reflects the author’s views and the Programme Authorities are not liable for any use that may be made of the information contained therein.

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5. PROJECT DESCRIPTION

5.1 Introduction

5.1.1 This chapter of the Environmental Statement (ES) presents the details of the Perpetuus Tidal Energy Centre (PTEC). PTEC is being developed to facilitate the demonstration of tidal devices, to support technological development, and to provide the opportunity to collate operational data during deployment. The project aims to support and speed up the process of developing tidal technologies to full commercialisation by providing a facility to allow a range of technology developers to take the step from testing individual devices to installing and optimising the performance, operation and maintenance of small arrays of devices up to 10MW in output.

5.1.2 PTEC will be the world’s first multi-technology tidal array demonstration facility. PTEC will support the development of the industry, by allowing developers to demonstrate their tidal devices in ‘real world’ conditions as well as providing a research and development opportunity to develop understanding of operating tidal arrays and their interaction with the marine environment. PTEC represents the next step in the commercialisation of tidal energy; it will move the industry beyond the testing of single tidal devices (including early prototypes), such as that offered at the European Centre (EMEC) testing facility in Orkney, providing instead, commercial demonstration.

5.1.3 The project will provide the electrical supporting infrastructure to connect a number of tidal devices and arrays located at ‘berths’ within the PTEC development site. The project also aims to secure a broad consent envelope which will encompass the range of tidal devices and arrays with potential to be installed and operated at the PTEC facility. The key benefit of PTEC is in substantially reducing development risk, cost and timetable to construction. PTEC differs from traditional renewable energy construction projects in the following ways:

• PTEC will cater for a wide range of tidal technologies, types and sizes; and • Tidal devices will be installed and operated, then potentially removed and replaced (hereafter referred to as “repowering”, see Section 5.15), before the offshore site is decommissioned at the end of the duration of the Marine Licence.

5.1.4 A key objective of PTEC will be to commercially demonstrate the long term running, management and monitoring of arrays of proven tidal devices (previously tested at EMEC or equivalent sites). Maintenance work for these proven tidal devices is expected to be less than for the earlier prototypes, and is expected to focus on the management and monitoring aspects of arrays, paving the way for larger commercial deployment of proven tidal devices elsewhere.

5.1.5 This chapter describes the following stages of the development:

• Construction; • Operation; • Maintenance;

• Repowering, and • Decommissioning. 5.1.6 As detailed in Chapter 1, Introduction, the following terminology is used throughout this chapter and the wider ES when describing the project:

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• Array A set of multiple devices connected to a common electrical grid connection • Array area The whole area taken up by an array, including the spaces in between the tidal devices • Berth Discrete area for tenant project demonstration • Berth Process for determining tenants to deploy their tidal technology in selection a berth at PTEC process • Development Defined by The Crown Estate Lease boundary, the area within site which the tidal devices/arrays will be deployed along with associated infrastructure such as inter-array cables, export cables, marker buoys, site monitoring equipment and electrical connections to the export cables • Device area The plan view area taken up by a device

• Device type A characterised group of devices (e.g. surface piercing floating, piled tower, transverse axial)

• Footprint The area physically in contact with the seabed or ground • Offshore site Cable corridor and development site combined • Onshore site The landfall location at Castle Cove, the short onshore cable route between landfall and the onshore infrastructure (up to and including PTEC substation/control room), and the Flower’s Brook area where permanent and/or temporary infrastructure will be installed

• PTEC The project • PTEC Ltd The developer • Repowering The removal of a tenant’s infrastructure at the end of a demonstration period and replacement with new tenant infrastructure

• cable The corridor within which the export cables will be routed from the corridor development site to the landfall location at Castle Cove

• Swept area The cross-sectional area of the Tidal Energy Converter (TEC) perpendicular to the current flow

• Tenant/ One company which may have more than one tidal technology developer

• Tidal One complete unit (as shown in Figure 5.1) including: device/device o Tidal Energy Converter(s) (TEC; i.e. rotors and nacelle) o Foundations o Support structure o Surface piercing superstructure • Tidal A model of device (e.g. SeaGen, BlueTEC, Triton) technology

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5.1.7 For the purposes of this EIA, Figure 5.1 illustrates the terminology used in defining the tidal devices and the component parts.

A - surface piercing platform (e.g. Tidal Stream Ltd B - surface piercing tower (e.g. MCT Siemens platform (plus multiple Tidal Energy Converters e.g. technology). Image source: Marine Current Schottel)). Image source: www.tidalstream.co.uk Turbines

C - surface piercing floating device (e.g. Bluewater D - Seabed mounted single rotor (e.g. Alstom technology). Image source: www.bluewater.com TGL). Image source: www.alstom.com Figure 5.1: Device terminology used within this ES for different device type examples

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PTEC flexibility – The need for a device neutral approach

5.1.8 As a commercial operation, the demonstration facility must be able to attract a wide spectrum of tidal devices that are likely to require demonstration over the foreseeable future. There are a number of key considerations which are particular to PTEC and which have a bearing on the EIA approach used. The range and flexibility sought within the consent application has been limited by careful consideration of development scenarios designed to rationalise the likely approach to development and to set workable limits on potential impacts. As a result, a series of key design and development principles are outlined in this chapter and used to shape the impact assessments undertaken. This approach allows a range or “envelope” of design parameters, and the likely worst case of each parameter to be defined. This approach is tested in planning law and referred to as the ‘Rochdale Envelope’ approach (described further in Chapter 2, Legislation and Policy).

5.1.9 Characterisation of the Rochdale Envelope for PTEC has focussed on those characteristics known to interact with key environment receptors i.e. foundations, moving parts, and visible components.

5.1.10 Consultation with 39 advanced and earlier stage tidal technology developers was undertaken in 2013 in order to inform the Front End Design (FEED) and EIA project description; this consultation continued with various developers throughout 2014, as discussions with potential tenants are ongoing. The developers involved in the consultation process comprised those with tidal devices that would have a Technology Readiness Level (TRL) of between 6 and 9 (prototype demonstrator to commercial prototype) at the time of planned deployment at PTEC. The results of the developer consultation and on-going discussions have been used to determine the technical requirements and level of interest of developers which has then been used to select which device types are appropriate for defining parameters for the Rochdale Envelope (see Sections 5.3 and 5.17). The project description presented here has been developed to provide flexibility to allow the construction and operation of a range of device types and tidal technologies.

5.1.11 It is important to note that due to the wide range of tidal devices available, the tidal technologies referred to within this document are provided as examples for reference only and are to be considered representative of the range of device types likely to be utilised at the PTEC demonstration facility. A review of these tidal technologies has allowed the identification of realistic worst case parameters for each device type; these have then been used to define the Rochdale Envelope in terms of the device parameters (see Sections 5.4, 0 and 0), and the relevant worst case scenarios for the project as a whole are used in the impact assessments.

5.1.12 Flexibility within the Rochdale Envelope built in to this EIA, and the resultant consent conditions, will allow PTEC to adapt to future changes and to accommodate continued improvement in tidal device installation techniques, health and safety, operation and maintenance, and reductions in cost of energy, as part of ongoing efforts to maximise industry viability. For the purpose of the EIA, flexibility is particularly important in the following areas, with a more detailed review of each item provided in the subsequent sections of this chapter:

• Total number of tidal devices; • Layout of tidal devices within the development site (location, density, array spacing); • Device types and their mix across PTEC;

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• Foundation / mooring types; • Location of electrical hubs and monitoring equipment; • Number and routing of inter-array cables; and

• Location of navigational aids.

5.1.13 Following consent, the berth selection process will conclude and result in final berth allocation at PTEC to developers. Array deployments may be of varying duration (see Section 5.12) and the berth selection process will be repeated if/when space for deployment becomes available.

5.1.14 To support the wide variety of device types which may be installed, the infrastructure installed by PTEC Ltd for the life of the PTEC project will have to be as flexible as possible in order to accommodate different requirements from tenants. As yet there is no standardised method for connecting tidal devices to the grid; a number of different options are adopted by different developers. Section 5.9 outlines the electrical infrastructure that will be deployed at PTEC.

5.1.15 The construction methodology provided within this document is based on existing tidal energy projects and consultation with developers/potential tenants. The design and construction of the permanent works (namely onshore infrastructure, onshore and offshore export cable alignment and landfall) is relatively refined (see Sections 5.10 to 5.13), whereas the final position of tidal devices will be decided on a case by case basis, by the tenants themselves, dependent on the device type and influenced by a number of parameters, such as:

• Environmental parameters; o Depth o Tidal resource

o Substrate • Environmental mitigation identified in the EIA and consent conditions; and • Wake effects, depending on the tidal technology and number of tidal devices to be installed.

5.1.16 The information presented in this chapter has been used to inform the technical chapters contained within the ES and is considered to represent the Rochdale Envelope of PTEC for use within the Environmental Impact Assessment (EIA). Although best efforts have been made to incorporate reasonably foreseeable developments, tidal devices outside of this envelope will require further assessment before deployment is possible. Prior to each deployment, documentation will be submitted to the Marine Management Organisation (MMO) outlining the parameters of the tidal devices to be installed as well as providing details of the construction methodology, operation and maintenance (O&M) strategy, and the array removal (decommissioning) methodology. A statement of confirmation, outlining that the deployment fits within the Rochdale Envelope will be submitted by PTEC Ltd to the MMO for approval. If the deployment is out with the Rochdale Envelope, additional consenting or amendment to the PTEC consent will be required before deployment.

5.1.17 The details of the tidal device final positions will therefore be dependent on a number of

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studies such as targeted site investigations for geology, unexploded ordnance (UXO), benthic ecology, archaeology, and metocean which will be undertaken post consent.

5.1.18 In addition to the development site flexibility, options are included within the onshore site to allow the consent to be future proofed in relation to land availability and to allow flexibility to avoid constraints if identified during pre-construction site investigations.

Project overview

5.1.19 PTEC will provide facilities for up to 60 tidal devices, with an aggregated maximum capacity of up to 30MW, encompassing a maximum development site area of 5km2. The different device types and potential numbers of each are described in Sections 5.4 to 5.7.

5.1.20 The 5km2 development site will be segregated into a number of berths (a maximum of 6 berths and a minimum of 3 berths). Each berth will consist of a defined area, leased to a developer in which they will demonstrate their tidal technologies. Berth arrangements are discussed further in Section 5.7.

5.1.21 PTEC will provide developers with grid connection infrastructure via subsea export cables, as well as navigation aids and site monitoring equipment to allow developers to utilise the area to demonstrate their tidal technologies.

5.1.22 The project duration takes into account the time required for repowering works as well as construction and decommissioning, allowing up to 20 years of operation for each tenant. Therefore the overall life of the project will be 25 years.

5.1.23 The key features of PTEC are:

2 • 5km development site;

• Up to 30MW total installed generation capacity; • The Lease conditions for PTEC should allow for up to 20 years of operation per tenant and up to 5 years for pre-construction, construction, repowering, and decommissioning works, i.e.25 years for the PTEC project in total; • A maximum of six berths, minimum of three berths within the development site • Up to 60 (total) submerged tidal devices (although a maximum of 30 may be surface piercing); • Berth capacities may vary between 1MW and 10MW (to a total of 30MW); • Tidal device capacities may vary from 100kW (0.1MW) to 6MW; and

• 6 export cables grouped into 3 bundles of 2 cables each.

Offshore overview

5.1.24 Once operational the facility would include the following offshore elements, installed by PTEC Ltd for the life of the project:

• Surface floating navigation buoys Section 5.8; • A subsea cable network Section 5.9, including:

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o Export cable(s) to shore; o Cable protection measures (where necessary); and • Site monitoring equipment Section 5.8.

5.1.25 Developers/tenants will install the following project elements at PTEC, in addition to the infrastructure installed by PTEC Ltd:

• Tidal devices, incorporating: o Foundation structures and associated support and access structures Section 5.5; o Tidal Energy Convertors (TECs) Section 5.4; and o Seabed preparation measures for foundation construction (where necessary). • Possible use of electrical hubs or connectors as a means to allow multiple tidal devices to export power through the berth’s export cable(s) Section 5.9; • Site monitoring equipment Section 5.8; and • Inter-array cables within each berth to connect tidal devices to one another and/or an electrical hub Section 5.9.

5.1.26 The device types included in the Rochdale Envelope for this project were identified through a process of developer consultation, to determine the technical requirements and level of interest in PTEC. Environmental considerations were also a key aspect. This approach allowed the Rochdale Envelope to be defined, capturing the likely range of tidal devices that could reasonably be expected to be installed at PTEC.

5.1.27 Consultation with developers has identified that berths of 1MW to 10MW may be required. The berth sizes and numbers will be identified during the berth selection process, depending on the requirements of prospective tenants, and will be finalised post consent. The maximum berth capacity will be 10MW and site capacity will be 30MW. This chapter describes the various foreseeable options for each berth in order to define worst case scenarios for the whole development site for the different parameters. Chapters 7 to 25 consider the relevant worst case scenario for each impact for the development site as a whole.

5.1.28 The number of berths and their capacity may vary during periods of repowering (as discussed in Section 5.15). Within these development scenarios, a number of key principles have been formulated to allow the project description to be defined. These are based on a review of existing tidal devices and the likely capacity of each device type as well as any limitations associated with The Crown Estate Lease conditions. Detailed principles relating to the foundations, moving parts, and surface piercing structures are discussed in Sections 5.4 to 5.6

Onshore overview

5.1.29 The key components of the onshore works associated with PTEC include:

• Landfall works, including possible transition pits; • Cable installation from landfall to the project substation/control room;

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• A dedicated project substation and control room, either two separate buildings or one combined building; • Possible levelling works;

• Parking area; • Possible alterations to the private access roads within the onshore site; • Temporary closure and/or diversions to the public rights of way and coastal path through Flowers Brook/Castle Cove, with possible temporary enabling works to the public rights of way and slipway during this time; • Temporary laydown and construction area, including site fencing;

• Temporary portacabin facilities within existing hard standing or the footprint of a feature described above, e.g. temporary laydown and construction area; and • Enabling works, including security fencing/provisions and possible tree / scrub clearance.

5.1.30 Various cable landfall locations were considered (see Chapter 3, Site Selection). The selected landfall location is Castle Cove to the west of Ventnor. Landfall options within the onshore site include:

• Cables trenched/buried, making landfall adjacent to the existing slipway;

• Using an existing 600 mm diameter outfall pipe as a cable duct for some or all of the export cables; or • Horizontal Directional Drilling (HDD) under the shoreline from a suitable location close to the proposed substation/control room, with cable emerging in the shallow subtidal for connection to the marine export cables.

5.1.31 Figure 5.2 below provides a representative diagram of the PTEC project.

5.1.32 In addition to the above, cabling and enabling works will be required to connect the project substation/control room to the existing Southern Electric Power Distribution (SEPD) substation at Wootton Common. Cabling works on the ‘grid side’ of the project substation/control room and any further enabling works will be consented and undertaken by SEPD and as such fall outside of the scope of this ES.

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Figure 5.2 - Schematic diagram of the PTEC project with cable trenching option.

Embedded mitigation

5.1.33 During the development of the engineering design a number of embedded mitigation measures have been included to reduce the potential impacts of the project. These include:

• Avoiding development in a number of designated sites, including:

o Heritage Coast; o Sites of Special Scientific Interest (SSSI); and o Area of Outstanding Natural Beauty (AONB).

• The South Wight Maritime Special Area of Conservation (SAC) could not be avoided for routing of the subsea export cable. However, the routing will avoid key features to minimise impacts on the seabed ecology as well as reducing physical risks to the export cable, in particular: o Avoid or minimise crossing of: . slopes; . scarps; . ridges; . scour lines; or . other areas where there are rapid variations in bathymetry which could represent a reef feature. o Using appropriate cable protection to avoid the cable moving around on the seabed. • Avoiding the disused munitions disposal site to the east of PTEC

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• Avoidance of protected wrecks • Limiting the number of surface piercing devices (30) compared with the maximum number of submerged devices (60). In addition, the maximum number of the highest device types is further limited to 27; • The substation/control room building will be designed to be in-keeping in size and finish to the existing Southern Water Services Ltd pumping station;

• Substation/control room locations have been selected with the aim of being unobtrusive and minimising impacts where possible; • Where appropriate, screening (e.g. trees) will be used to reduce the visual impact of the substation/control room; • The substation/control room fence will be closed wooden boarded to minimise noise propagation and visual impacts; and

• Footpath closures will be limited to a maximum of 8 weeks during the winter period.

5.1.34 Further to the reduction in CO2 emissions associated with developing renewable energy, throughout the design of the project, PTEC Ltd has given consideration to the reduction of carbon emissions. In particular the following elements have been considered:

• Onshore Cabling:

o During the assessment of onshore route trajectory, a thorough investigation was conducted into the possibility of using an existing outflow pipe for cable landfall to avoid trenching or HDD and thus minimise emissions during these processes. This option, whilst still under consideration, is no longer preferred due to the de-rating of the cables in the pipe due to heat build-up and risks associated with installation in the pipe.

• Offshore Cabling: o The offshore cable will be largely surface laid due to the hard seabed at the site; this reduces the amount of time a large cable construction vessel will be required on site. However, the cable will still require protection and stabilisation. The preferred method of cable stabilisation and protection is to use rock bags (filter units) filled with locally sourced rocks.

o These units are far less energy intensive than the alternatives, being the use of concrete mattresses (with larger embodied carbon), rock placement (with quarried materials usually sourced from Northern Europe), or split pipe sleeves (using cast steel and lengthening installation time with the cable vessel). • Offshore Construction:

o For the installation phase of the subsea cables, the methodology has been developed to allow the use of non-DP vessels - which would save an estimated 6 to 22 tonnes of fuel (16 to 58 tonnes CO2) per day [20 to 30t fuel per day (55 to 80t CO2) for a large DP vessel compared to 2 tug boats at about 4 to 7 tonnes of fuel each per day (10 to 18 tonnes CO2)]. Although it should be noted that the project is not restricting the type of vessels to be used, so ultimately, DP vessels may present an overall more advantageous for the project.

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• Civil works: o The substation/control room and onshore construction elements (including trenches, transition pits, hardstandings, and associated works and enabling works) have been designed / specified to enable (smaller) local contractors to undertake the works; resulting in a minimisation of travel and associated carbon emissions, but would also benefit the local economy. Local contractors have already been consulted on these works.

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5.2 Site Description

Offshore site description

5.2.1 The PTEC offshore site is located in the English Channel, off St Catherine’s point on the south coast of the Isle of Wight, as can be seen in Figure 5.3. The export cables pass to the north east of the development site, making landfall just west of Ventnor.

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Figure 5.3 - Location of the offshore site.

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5.2.2 The Crown Estate Agreement for Lease defines the development site boundary shown in Figure 5.3 and defined by the coordinates shown in Table 5.1. The development site was selected by assessing the flow velocities around the region and the suitable bathymetry of the seabed, as well as taking into consideration environmental and physical constraints, including distance from land, designated sites, protected wrecks, munitions dumps, and shipping lanes. The leased area is aligned approximately parallel with the direction of tidal flow and the bathymetry features of the seabed.

5.2.3 The development site is linked to the land by an additional leased seabed area; the subsea cable corridor, the coordinates of which are displayed in Table 5.2.

Table 5.1 - PTEC development site co-ordinates (WGS84)

Latitude Longitude

50.546199 -1.320070

50.555301 -1.279539

50.554401 -1.269209

50.561599 -1.239809

50.557201 -1.237499

50.540901 -1.293529

50.539798 -1.316210

Table 5.2 - PTEC subsea cable corridor co-ordinates (WGS84)

Latitude Longitude

50.560587 -1.243973

50.561599 -1.239809

50.557201 -1.237499

50.569541 -1.240560

50.568929 -1.235390

50.581322 -1.221089

50.580294 -1.216582

50.589252 -1.220814

50.590914 -1.216307

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5.2.4 PTEC offers potential tenants a range of differing physical characteristics, within which to deploy their tidal devices. This is due to the good tidal resource and the range of water depth and bathymetry, throughout the development site. The development site will be divided into between 3 and 6 berths, each offering different conditions suited to different types of tidal devices across the development site. The berths are connected by power export cables which will run along a single corridor and make landfall at the coast near Ventnor on the Isle of Wight.

5.2.5 The eastern side of the development site is located within St Catherine’s Deep, a tidally eroded seabed channel, with varying bathymetry across the site. The deepest waters (70- 80m below Chart Datum (CD)) lie in the east of the site and water depths gradually reduce through the central area (60m below CD) towards the west (50m below CD), with shallowest areas (35m below CD) in the northern extents.

5.2.6 The Isle of Wight is surrounded by areas of strong , most notably St Catherine’s Race to the south of St Catherine’s Point where the PTEC development site is located. Detailed monitoring of the tidal stream resource was undertaken using fixed Acoustic Doppler Current Profilers (ADCP). This revealed equally energetic tidal resources in the central and eastern extents of the site, with slightly lower tidal velocities and more prominent differences between ebb at flow tides in the shallower western area. The typical hub height flows in neap tides are around 1.5m/s whilst in spring conditions this increases to over 2.5m/s. Peak tidal velocities recorded during the fixed ADCP surveys was 3.2m/s. Mean Spring Peak velocities of between 2.6 and 2.9m/s have been predicted across the development site. The mean spring tidal range for the site is approximately 3.3m, based on gauge measurements taken from Sandown Pier1.

Onshore site description

5.2.7 Onshore project infrastructure will be located on a site west of Ventnor, approximately 100m inland from the coast, near to a residential area. The onshore site itself lies close to a Southern Water Services Ltd pumping station (see Figure 5.4) and includes a council owned recreational field known as ‘Flowers Brook’, which is situated along the coastal pathway and is suitably flat and accessible. The Council field is dominated by amenity grassland and edged by species poor hedgerow and scrub vegetation. There is semi-natural broadleaved woodland to the eastern areas of the onshore site.

5.2.8 Other land uses in the onshore site include privately owned land (referred to as “Red Squirrel Ltd (RSL) land/caravan park”), and in the vicinity there is residential housing. A small stream runs from the east of the Southern Water Services Ltd land down the eastern boundary of the amenity grassland, following the steep north to south slope of the onshore site towards the coast, where it crosses the coastal path and runs onto the foreshore.

1 Sandown Pier Tide Gauge – Rosemount WaveRadar REX (location WGS84: 50o 39.0666’N 01o 9.18960’W

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Figure 5.4 - Onshore site

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5.2.9 PTEC Ltd intends to route the subsea cable corridor into Castle Cove, which lies to the west of Ventnor and to the east of Ventnor Botanical Gardens. The hilly coastline at the landfall comprises of small cliffs that develop into the downs with progression inland. Extensive coastal protection works were undertaken here during the mid-1990’s; the upper foreshore at Castle Cove is dominated by rock armouring using large boulders. Further down the shore there is a transition into natural boulders with bedrock and cobbles. (Figure 5.5).

5.2.10 To the south west of the onshore site there is a small concrete slipway which is surrounded by rock armouring. The slipway joins up with the coastal path, however there is no evidence that the slipway is regularly used and an alternative slipway is available approximately 100m to the west.

Figure 5.5 - The coastal protection scheme in the upper shore at Castle Cove moving to natural boulders.

5.2.11 Within this onshore site there are two possible locations for the substation and control room; within the grounds of the Southern Water Services Ltd land, and the adjacent RSL land/caravan park (Figure 5.4).

5.2.12 In 2001 a new concrete outfall pipe was installed from the Southern Water Services Ltd pumping station at Flowers Brook to a point about 90m offshore (55505.0E 76975.0N). The end of the pipe is submerged by approximately 1.5m at mean low water springs (MLWS). The pipe has an internal diameter of 600mm and is encased in a concrete and rock berm as can be seen in Figure 5.6. The pipe passes across the beach and shoreline from the , then diagonally upward within the cliff, before levelling out and travelling about 120m inshore

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via 3 manhole covers and a number of 35degree bends. Following rerouting of the Southern Water Services Ltd systems, according to Southern Water Services Ltd, this outfall pipe has not been activated in recent years, although it is still connected to the system and could potentially be used during extreme water levels as an emergency overflow.

Figure 5.6 - Pipe ‘berm’ at low tide

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5.3 Review of Existing Tidal Technologies

5.3.1 A detailed review of the device types and tidal technologies most likely to seek and be suitable to be deployed at PTEC has been undertaken. A key objective of this review was to allow a Rochdale Envelope to be defined for PTEC, which encompasses an appropriate range of tidal devices and technologies whilst limiting environmental impacts to within acceptable limits. The results of the review are summarised below.

5.3.2 Based on the developer consultation discussed previously, significant consideration has been given regarding which device types to include in the assessment. Those outlined in this chapter represent the device type parameters that will fall within this Rochdale Envelope. There is a wide range of novel device types available, however in order to achieve a meaningful impact assessment some limitations were required. The device types included in this project description, and therefore assessed in this EIA, are deemed to represent the most suitable parameters for deployment at PTEC. As discussed in Paragraph 5.1.3, any device types which are not encompassed by the Rochdale Envelope described in this chapter, but which are proposed for deployment at PTEC following the berth selection process, will require additional licencing from the MMO.

5.3.3 The main methods for extracting tidal stream energy under development use axial flow TECs and transverse axis TECs. The devices considered for PTEC fall into these technology types. Reciprocating hydrofoil and other novel systems are also in development but are not considered further in this ES.

5.3.4 The tidal technologies that may be installed at PTEC under the Rochdale Envelope have the following key elements which are common across the device types:

• A foundation or anchor on the seabed; this could be a drilled foundation/anchor attaching a substructure to the seabed or a gravity foundation/anchor;

• A supporting substructure or mooring - this supports or tethers the tidal device in the fast flowing water column; • A Tidal Energy Convertor (TEC, including nacelle or generator and rotor blades), where tidal movement drives the blades and electricity is generated; and • Cable connections: where electricity is transmitted (possibly via a hub or connector) to a shore based grid connection. 5.3.5 The principle device types considered suitable for the Rochdale Envelope are shown below in Table 5.3 with example technologies.

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Table 5.3 - Tidal device types with examples of existing technologies, forming part of the Rochdale Envelope, and with potential to be deployed at PTEC

Example Device Technology Device Type

Bottom mounted open rotor axial flow

Seabed mounted single rotor. Single open rotor. Fully submerged. Base typically formed from tripod, quadrapod or monopile foundation with drilled pin piles, gravity base or drilled monopile. Example Developer: Alstom Device technology: Deep Gen

Image source: www.alstom.com

Fast seabed mounted single rotor. A seabed mounted single rotor but with a faster tip speed (see Section 5.3) Example Developer: Voith Hydro Device technology: HyTide

Image source: www.voith.com

3 rotor seabed mounted platform. Bottom mounted platform with 3 open axial flow TECs, fully submerged. Base typically gravity base. Example Developer: Tidal Energy Limited (TEL) Device technology: Deltastream

Image source: www.tidalenergyltd.com

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Example Device Technology Device Type

Twin rotor tower. Bottom mounted, pin piles or monopile with a surface piercing tower. Example Developer: Marine Current Turbines (MCT) Siemens Device technology: SeaGen

Image source: Marine Current Turbines

Floating/buoyant open rotor axial flow

Twin rotor floating. Surface piercing floating superstructure with catenary moorings/anchors to hold the device in place. Example Developer: Scotrenewables Device technology: Scotrenewables Tidal Turbine

Image source: www.scotrenewables.com

Twin rotor buoyant mid water. Mid-water column (floating submerged), 2 TECs on single buoyant platform located below the sea surface. Platform maintained in position with tension cables secured with pin piles or gravity anchors. Example Developer: SME Device technology: PLAT-O

Image source: www.sustainablemarine.com/

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Example Device Technology Device Type

Multiple rotor buoyant platform. Surface piercing with buoyant superstructure attached to seabed, with monopile, pin piles or gravity structure utilising mooring lines or a rigid structure. Multiple TECs typically installed on a single platform. Example Developer: Tidal Stream Limited Device technology: Triton

Image source: www.tidalstream.co.uk

Bottom mounted ducted

Ducted axial flow TEC. Fully submerged, bottom mounted. Typically gravity base. Example Developer: Clean Current Power Systems Device Technology: Tidal Turbine Generator

Image source: http://thinkprogress.org

Example Developer: OpenHydro Device Technology: Open-Centre Turbine

Image source: Nova Scotia Power Ltd

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Example Device Technology Device Type

Transverse axis

Bottom mounted transverse axis. Surface piercing support columns on monopile foundations. Example Developer: Kepler Device technology: Turbine generator unit

Image source: www.keplerenergy.co.uk

Floating transverse axis. Vertical transverse axis TECs mounted on a floating device, similar to axial flow floating device type. Example Developer: Bluewater Device technology: BlueTEC

Image source: www.bluewater.com

5.3.6 Following a review of the existing tidal technologies, it was possible to formulate a Rochdale Envelope in which the range in parameters of different device types could be accommodated under realistic worst case scenarios in relation to the following characteristics:

• TEC generator type (how the tidal energy is converted into electricity); • Foundation design / type (how the device is secured in place); and

• Surface piercing elements (how the device interacts with the sea surface).

5.3.7 Each of the above attributes will be discussed in further detail in Sections 5.4 to 5.6

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5.4 Tidal Energy Converter (TEC) Envelope

5.4.1 A number of representative tidal technologies have been considered in order to capture the likely range of TECs that may be demonstrated at PTEC.

5.4.2 This section provides the worst case scenarios for the following TEC types. Where relevant, technical chapters (Chapters 7 to 25) of this ES will identify which rotor type, or combination of types, presents the worst case scenario for each receptor:

• Axial flow TEC o Open rotor o Ducted

• Transverse axis TEC

5.4.3 A number of companies are developing open architecture platforms that would, with modification, accept a range of TECs such as Tidal Stream Ltd, shown in Figure 5.7 and Figure 5.8, with different TECs mounted on the platform structure. The TECs considered within this section may feasibly also be fitted to these platform device types.

Figure 5.7 - Tidal Stream Ltd with 6 Figure 5.8 - Tidal Stream Ltd with 36 small rotors large rotors (Image source: (Image source: www.tidalstream.co.uk) www.maritimejournal.com/__data/assets/image/0004 /974965/SCHOTTEL_Triton-platform-with-STG- turbines_2014_07.jpg) 5.4.4 Typically each rotor will be coupled via a gearbox to a generator. Some devices may adopt a direct drive system (such devices do not require a gearbox), allowing the rotor to directly drive the generator. Most machines are variable speed, pitch control with frequency converters. Some devices may yaw to align with the tidal flow. Step-up transformers are commonly installed within the devices, stepping up generation voltage (typically 690V to the export voltage (typically 6.6kV or 11kV)).

5.4.5 The worst case scenario for the TECs is defined in terms of the swept area, tip speed, clearance from the water surface, and clearance from the seabed as these are the parameters which are relevant to potential impacts on receptors (e.g. fish, marine mammals, physical processes, and shipping/recreational boating).

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Axial flow TECs

5.4.6 Axial flow TECs are currently the dominant, most well developed type of TEC on installed or planned technologies, with a number of axial flow devices installed at a pre-commercial stage. These devices extract energy from moving water in much the same way as wind turbines extract energy from moving air.

Open rotor axial flow TECs

5.4.7 Generally, axial flow rotors are composed of two or three rotor blades which are connected to a central hub and into the nacelle via a drive shaft. Figure 5.9 and Figure 5.10 shows two examples of open rotor TECs.

Figure 5.9 - Alstom/TGL (Image source: Figure 5.10 - MCT SeaGen S (Image source: www.alstom.com). Marine Current Turbines). 5.4.8 TECs that may be installed at PTEC range from small (< 500kW, which may be installed as multiple TECs on a platform device type), to larger TECs likely ranging up to 2MW each. The capacity of each device could range from 100kW to 6MW.

5.4.9 The most well developed fully floating (e.g. Scotrenewables and Bluewater) devices utilise twin axial flow rotors suspended below a floating hull on retractable support arms. Such a device passively yaws about its turret connection to the mooring chains with the change in tidal flow direction. It inherently aligns itself with the flow during times of sufficient flow to generate power.

5.4.10 Table 5.4 provides a review of parameters for the example tidal technologies outlined in Table 5.3 in order to define the worst case scenario for open rotor axial flow device types. A range of capacities are provided for each device type and the maximum number of devices per berth is based on the smallest capacity from each range as a factor of the largest berth capacity (10MW). Devices of less than 0.5MW are deemed to have smaller parameters than those shown in Table 5.4 and are therefore captured under the worst case scenario. As discussed previously, the maximum number of devices per berth is limited to 20.

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Table 5.4 - Axial flow device parameters (worst case highlighted yellow)

Device type Max No. Max Max tip Max Max Max Max with example of devices no. speed rotor device array development technologies per berth rotors diameter swept swept site swept (not per (m) area area (m2) area for exceeding device (m2) each device 10MW) type

Seabed 20 1 17m/s 18m 254.5m2 5090m2 15,270 m2 mounted single rotor e.g. (20 x 2 Alstom TGL 254.5m ) (0.5-2MW)

Single rotor 20 1 41m/s Up to 201m2 4020m2 12,060m2 (fast tip speed) 16m e.g. Voith Hydro (worst (20 x case for 201m2) (0.5-2MW) rotors up to 16m diameter)

Twin rotors e.g. 7 2 12m/s Up to 904m2 6328m2 18,984m2 MCT, 24m Scotrenewables (worst (2x (7 x 2 2 (1.42-3MW) case for 452m ) 904m ) rotors of 20-24m)

Seabed 7 3 31m/s Up to 942m2 6594m2 19,782m2 mounted 20m platform e.g. (worst (3 x (7 x 2 2 Tidal Energy case for 314m ) 942m ) Limited (1.42- rotors of 3MW) 16-20m)

Mid water 20 2 25m/s 12m 226m2 4520m2 13,560m2 column floating platform e.g. (2 x (20 x 2 2 SME (100kW- 113m ) 226m ) 500kW)

Seabed 8 36 25m/s 4.5m 576m2 4608m2 14,040m2 mounted small (16m2 x multiple rotor rotors 36) (8 x 2 platform e.g. 576m ) Tidal Stream Ltd (1.25- 2.99MW)

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Device type Max No. Max Max tip Max Max Max Max with example of devices no. speed rotor device array development technologies per berth rotors diameter swept swept site swept (not per (m) area area (m2) area for exceeding device (m2) each device 10MW) type

Seabed 3 6 large 31m/s Up to 1884m2 5652m2 16,956m2 mounted rotors 20m multiple rotor (6 x (3 x 2 2 platform e.g. 314m ) 1884m ) Tidal Stream Ltd (3-6MW)

5.4.11 Axial flow device types are typically bottom mounted, but can also be mounted on floating device types. TECs range in size, with rotor diameters between 4.5m (50kW) and 24m (2MW). The number of TECs range from a device with a single TEC (e.g. Alston, Voith) to a platform device type (e.g. Tidal Stream Ltd) with up to 36 small axial flow TECs (each with <100kW capacity and <5m diameter) to six 1MW axial flow TECs.

5.4.12 The maximum capacity for a single device in this EIA is 6MW in which case there would be only one device in a berth.

5.4.13 Table 5.4 outlines the maximum swept area for an array (for the largest, 10MW array size) which ranges from 4020m2 to 6594m2.

Figure 5.11 - Example of submerged floating platform with surface piercing ‘spars’ (Image source: Tidal Stream Limited).

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5.4.14 The worst case swept area for a single axial flow device is associated with device types with the greatest number of large (~18-24m) rotors mounted on a single device. This is represented by a multiple rotor platform device type e.g. Tidal Stream Ltd which could have up to 6 large rotors, giving a swept area per device of 1884m2 (Table 5.4). However there would be a maximum of 3 devices of this type in a 10MW array.

5.4.15 The worst case scenario for an array is based on the 3 rotor seabed mounted device type (e.g. TEL) as there could be 7 of these devices, giving a maximum (10MW array) swept area of 6594m2.

5.4.16 The overall worst case scenario for the swept area of axial flow TECs is based on all berths (e.g. 3 x10MW berths, 6 x 5MW berths, etc.) being taken up by the array type with the largest swept area (i.e. 3 rotor seabed mounted platform type), giving a swept area of 19,782m2 for the development site.

5.4.17 The worst case scenario relating to tip speed is the fast seabed mounted single rotor device type, with rotor diameters of up to 16m (e.g. Voith Hydro), with a potential tip speed of 41m/s (60RPM for a 13m diameter rotor). The swept area of a single 13m diameter Voith Hydro device is 133m2 and there could be up to 10 devices of this type in a 10MW array.

5.4.18 Larger rotor diameters generally rotate slower and therefore have lower tip speeds e.g. 31m/s for rotor diameters up to 20m and 12m/s for rotor diameters up to 24m.

5.4.19 The clearance between the rotor tips and the water surface at Lowest Astronomical Tide (LAT) will vary dependant on device type and the water depth at the installed locations. Based on the review of existing tidal technologies, the surface clearance at LAT for the rotor tips of open rotor axial flow TECs range between 6 and 18m for submerged seabed mounted device types (e.g. Voith, Alstom, TEL). For surface piercing axial flow device types, minimum clearance between rotors and the sea surface could be a minimum of 3m (e.g. SeaGen). Under keel clearance is discussed in Chapter 19, Shipping and Navigation, and Appendix 19A, Navigation .

5.4.20 Clearance from the rotor tips of a device to the seabed will range from 3m to 32m depending on the water depth at the deployment location.

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Any devices/arrays of open rotor axial flow device types that fall within the worst case scenarios detailed below are considered to be within the Rochdale Envelope of this EIA: • A maximum single rotor swept area of 452m2 • A maximum device swept area of 1884m2 • A maximum array swept area of 6594m2 (10MW array) • A maximum overall site swept area of 19,782m2 (30MW total) • A maximum tip speed of 41m/s (for rotor diameters of up to 16m) • A maximum tip speed of 31m/s (for larger rotor diameters of up to 20m) • A maximum tip speed of 12m/s (for larger rotor diameters of up to 24m) • A minimum clearance for surface piercing device types with open axial flow TECs of 3m from the rotor tips to the water surface at LAT • A minimum clearance for surface piercing device types with open axial flow TECs of 3m from the rotor tips to the seabed • A minimum clearance for submerged device types with open axial flow TECs of 6m from the rotor tips to the water surface at LAT • A minimum clearance for submerged device types with open axial flow TECs of 3m from the rotor tips to the seabed Ducted axial flow TECs

5.4.21 Ducted axial flow TECs incorporate an axial flow TEC within a cowling/duct in order to capitalise on the venturi effect2 and maximise flow through the TEC housing. The rotor blade designs within the duct may vary from blades such as those used in an open rotor axial flow device (see Figure 5.12) to the multi-blade design such as that adopted by OpenHydro (Figure 5.13).

5.4.22 Table 5.5 presents the parameters for two example technologies; OpenHydro and Clean Current, which were used to define the Rochdale Envelope for ducted axial rotors.

Table 5.5 - Ducted TEC parameters (worst case highlighted yellow).

Example Max No. of Max no. Max tip Rotor Device Array Max technology devices per rotors per speed diameter swept area swept development berth (not device (m) (m2) area site swept exceeding (m2) area for each 10MW) device type

Clean 20 1 26m/s 10m 79m2 1,580m 4,740m2 Current 2

(250- 999kW)

OpenHydro 10 1 25m/s 16m 201m2 2,010m 6,030m2 2 (1-2MW)

2 Ducted devices use the Venturi Effect with the duct concentrating the tidal flow passing through the TEC

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5.4.23 Clearance of the ducted rotor from the seabed will range from 3m to 39m depending on the water depth at the deployment location. Clearance between the top of the duct and the water surface at LAT will range from 6m to 18m.

Figure 5.12 - Clean Current (Image Source: Clean Current). Figure 5.13 - OpenHydro (Image source www.OpenHydro.com).

Any devices/arrays of ducted axial device types that fall within the worst case scenarios outlined below, are considered to be within the Rochdale Envelope of this EIA: • A maximum single rotor swept area of 201m2 • A maximum array swept area of 2010m2 (10MW array) • A maximum overall site swept area of 6030m2 (30MW total) • A maximum tip speed of 26m/s • A minimum clearance of 6m from the ducted rotors to the water surface at LAT • A minimum clearance of 3m from the ducted rotors to the seabed Transverse axis device

5.4.24 Transverse axis device types differ to the traditional axial flow design, with blades rotating about an axis perpendicular to the direction of the tidal flow (Figure 5.14). Existing devices are small, rated at a few hundred kW, however developer consultation has identified that next generation machines are likely to be rated at 1 to 3MW, and may be suitable for deployment at PTEC. The number of transverse axis device types has been limited at PTEC, as embedded mitigation, to a maximum of 2 berths or 20MW across the development site.

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Figure 5.14 - Kepler transverse axis device (1MW per bay) (Image source: Kepler Energy). 5.4.25 Table 5.6 presents the parameters used to define the Rochdale Envelope based on the Bluewater technology and two different sizes of the Kepler technology.

Table 5.6 - Transverse axis device parameters (worst case highlighted yellow).

Example Max No. of Number Max tip Rotor Device Array Max technology devices of rotors speed diameter swept swept development per berth per device (m) area (m2) area site swept (not (m2) area for exceeding each device 10MW) type

(limited to 20MW)

Kepler 10 Single 18m/s Rotor is 600m2 6000m2 12,000m2 rotor 60m long (1-2.4MW) divided and 10m into diameter trusses

Kepler 4 Single Up to Rotor is 1350m2 5400m2 10,800m2 rotor 18m/s 90m long (2.5-3MW) divided and 15m into diameter trusses

Bluewater 10 Up to 4 Up to Rotor is 600m2 6000m2 12,000m2 floating small 18m/s 15m long platform with transverse and 10m (4 x 10 x transverse axis rotors diameter 15) axis rotors

(1-1.5MW)

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5.4.26 The worst case swept area for a single transverse axis device (one rotor between two support columns) is associated with the 2.5-3MW transverse axis device type which is up to 90m in length and 15m in diameter, giving an area of 1350m2. There could be up to 4 devices of this size in a 10MW berth.

5.4.27 The worst case scenario for an array is based on the more numerous, smaller (1-2.4MW) transverse axis device types. This device type is up to 60m long with a 10m rotor diameter and there could be up to 10 of these devices in a 10MW array, giving an array swept area of 6000m2.

5.4.28 Arrays of transverse axis devices would generally be aligned in one or two rows with each row sharing support structures (see Section 5.7). This type of device could be deployed in a maximum of 2 berths and therefore 2 x 10MW berths represents the greatest swept area for transverse axis devices, giving a total of 12,000m2 for the site with the other 10MW taken up by axial flow TECs.

5.4.29 Smaller transverse axis TECs may also be suspended vertically from floating platforms (e.g. Bluewater) as shown in Table 5.3.

5.4.30 The rotor blade linear velocity (tip speed) would typically be 18m/s (Table 5.6).

5.4.31 Clearance of the transverse rotor from the seabed will range from 3m to 34m depending on the water depth at the deployment location. Clearance from the water surface at LAT will be from 6m for seabed mounted transverse axis device types and from 3m for the floating vertical transverse axis device type.

5.4.32 The transverse axis device type represents the largest swept area of all device types but with a rectangular swept area, and a slow rotation speed. The technical chapters (Chapters 7 to 25) will identify the relevant worst case device type, which will take into account the characteristics of the rotor as well as the size and speed.

Any devices/arrays of transverse axis device types that fall within the worst case scenarios outlined below are considered to be within the Rochdale Envelope of this EIA: • A maximum single rotor swept area of 1350m2 (one rotor per device) • A maximum array swept area of 6000m2 (10MW array) • A maximum overall site swept area of 12,000m2 (NB, there will be a maximum of 2 berths of this type of device and so the 10MW berth option provides the greatest area across the site. The remaining berths would be taken up with an axial TEC (see relevant worst case swept areas above)) • A maximum tip speed of 18m/s • A minimum clearance of 6m from the rotor edge to the water surface at LAT for seabed mounted transverse axis device types • A minimum clearance of 3m from the rotor edge to the water surface at LAT for the floating vertical transverse axis device type • A minimum clearance of 3m from the rotor edge to the seabed

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5.5 Foundation System Envelope

5.5.1 The Rochdale Envelope for foundation types is focussed on the parameters relating to the footprint in contact with the seabed and the potential volume of drill arisings as these have the potential to impact on receptors. The parameters described in this section apply to the initial construction and repowering; the worst case scenario for the impact assessment assumes foundations are in new locations. Repowering is discussed further in Section 5.15.

5.5.2 Consultation with device developers undertaken during the PTEC FEED process identified the range of foundation currently being considered and those that may be developed in the near future. This ES considers foundations for seabed mounted and floating/buoyant devices, to ensure all likely scenarios are captured within the Rochdale Envelope and given thorough consideration in the impact assessment.

5.5.3 Detailed design of the foundation structures will be finalised once preferred locations are identified and site investigation works have been completed post consent. As such the range of values provided within this ES are indicative, and conservative worst case scenarios have been identified to support the impact assessment process.

Scour protection

5.5.4 Scour at PTEC is not considered to be a significant issue as the seabed is predominantly exposed bed rock and lacking sediments that could be vulnerable to scour around foundations and therefore protection is not considered in this EIA.

5.5.5 Foundation construction methodologies are discussed in Section 5.12.

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As a result of the project level assumptions outlined in Section 5.1, the following principles apply to defining the worst case scenario for foundations: • Numbers of larger capacity devices in a berth will be a factor of the device capacity and the berth capacity (e.g. 5 x 2MW devices in a 10MW berth) up to a maximum of 20 devices per berth. • Floating devices using catenary moorings with an anchor spread represents the largest seabed footprint (see Table 5.6) and these will only be installed in a maximum of 2 berths (the worst case scenario for these is therefore represented by two of the largest (10MW) berths. o Floating device types with catenary mooring will have a capacity of between 1MW and 3MW; and o The maximum number per berth (largest berth, 10MW) will be 10 x 1MW devices (i.e. 20 across the allowed 2 berths) • Devices with drilled monopiles or pinpiles may be installed at all berths (drill arisings are outlined in Table 5.8 and Table 5.9); o These devices may have drilled monopiles or pin-pile foundations. o Devices will be between 0.5MW and 6MW capacity • Hammered pile driving will not be used as the method of pile installation at PTEC, due to excessive impacts and seabed characteristics.

Where relevant, technical chapters (Chapters 7 to 25) of this ES will identify which foundation type presents the worst case scenario for each receptor.

Seabed mounted designs

5.5.6 Seabed mounted devices under consideration at PTEC may have foundations consisting of:

• Gravity bases; • Pin piles; or • Monopiles. Gravity base foundation

5.5.7 Gravity based structures (GBS) utilise the submerged mass of the foundation structure to resist environmental and operational loading on the device and maintain its stability. The footprint (the element of the foundation in direct contact with the seabed) of gravity foundations, proposed at PTEC would typically be very small (<9m2), with gravity bases often using 'feet' that focus the of the foundation on a small area of seabed (Figure 5.15). The weight of the foundations can sometimes cause the feet to penetrate the seabed (by up to 500mm). The use of feet minimises the requirements for seabed levelling as well as reducing the surface area of the foundation that is in direct contact with the seabed. Table 5.7 includes an option for a solid gravity base as a conservative worst case scenario. Some foundations may require levelling of a small area of the seabed. The levelling works would entail the use of a mechanical cutting dredger to remove the high points and the small amount of material would generally be removed at the same time, however depending on the

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design of the dredge used, the material may be left in situ. Alternatively rock or aggregate placement may be used to level the area, by filling in the low points; this would generally entail the use of a barge and excavator with a fall pipe and ROV. Ground levelling works have been taken into account in the worst case scenario footprint of 400m2 per gravity base device.

5.5.8 Gravity anchors are discussed separately, later in this section.

Figure 5.15 - Gravity base foundation utilising three ‘feet’ below device (Image source: Tidal Energy Limited). 5.5.9 A buoyant seabed mounted platform structure (e.g. Tidal Stream Limited (Figure 5.16)) utilises multiple axial flow rotors, mounted on a common support structure. The support structure is connected to a foundation mounted on the seabed by use of a universal/ball joint to allow the structure to move and yaw. The foundation for this device type could use a gravity base system, using the weight of the foundation to hold the device in place.

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Figure 5.16 - Gravity base structure example for a buoyant platform device type (Image source – Tidal Stream limited).

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Table 5.7 - Parameters of gravity base foundations (worst case gravity base highlighted yellow).

Device Max No. Foundation structure Device Array Max type of devices footprint (m2) footprint development per berth (m2) site footprint (not for each exceeding device type 10MW)

Seabed 7 Gravity base frame with 'rock Approximately 16.8m2 50.4m2 mounted 3 feet'. Some penetration into 3 x 1.0m 2 rotor seabed through structure's own diameter (2.4m x 7) platform weight. Range of penetration is footprints per e.g. Tidal 50mm for very strong rock to device. Total Energy 540mm for very weak rock. of 2.4m2 per Limited device (1.42- Gravity base could be up to 3MW) 1000 tonnes for 2MW device

Ducted 20 Steel or reinforced concrete Gravity 8000m2 24,000m2 axial flow structure, gravity based foundation 2 e.g. Clean foundation most likely. Foot print structure = (400m x Current could be up to approximately 400m2 20) (0.5MW- 20m x 20m for an up to 2MW 2MW) device; up to approximately 600 tonnes for a solid gravity base although this is conservative as it is likely that feet would be used.

(see Table 5.7 for gravity anchors for floating devices)

Multiple 8 Gravity base could be 13 x 17 m = 1768m2 5,304m2 rotor approximately 13x17x4m (2,000 221m2 2 buoyant tonnes) (221m x 8) platform e.g. Tidal Stream Ltd

(1.25 – 6MW)

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Pin pile foundation

5.5.10 Fixed devices utilising multiple piles generally consist of a tripod or quadrapod structure typically using 3 or 4 pin piles. A socket is drilled into the seabed, typically between 1.0 – 2.5m in diameter and the pin pile is inserted into the socket and grouted into place. The structure is then grouted or swaged to the pin pile to provide a sound connection.

5.5.11 Due to the hard substrate in the development site, drilling (including percussive drilling with ‘down hole hammers’) will be required to install piled foundations (pin piles or monopiles). Some piles will be self-drilling, others will require an annulus to be drilled, of sufficient size to accommodate the pile. As discussed further in Section 5.12, this will create spoil arisings from the drilling process. Indicative volumes of drill arisings from the respective foundation types are shown in Table 5.8 below along with foundation footprints.

5.5.12 In some cases, screwpiles may be used; these are steel piles with helical steel plates welded to the pile shaft in accordance with the ground conditions. Screwpiles are wound into the seabed much like a screw into wood, using (temporary) rotary hydraulic equipment. The pile diameters and thus drill arisings are broadly similar to drilled pin piles.

5.5.13 A buoyant seabed mounted platform structure (e.g. Tidal Stream Limited) could be pinned to the seabed using a pin pile lattice frame structure (Figure 5.17) requiring up to 6 pin piles to secure the device.

5.5.14 Single or twin rotor seabed mounted axial flow devices may use a tripod pin pile foundation structure as shown in Figure 5.18.

Figure 5.17 - Pin pile lattice frame structure example for a buoyant platform device type (Image source – Tidal Stream limited).

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Figure 5.18 - Seabed mounted pin pile foundation (Image source: www.westislaytidal.com).

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Table 5.8 - Parameters of pin piled foundations (worst case pin pile highlighted yellow).

Device type Max No. of Foundation structure Device Array Max Drill arisings Drill Max. drill devices per berth footprint footprint (m2) development per device (m3) arisings arisings in the (not exceeding (m2) site footprint per array development 10MW) for each (m3) site for each device type device type

Seabed mounted 20 Tripod with piles up to 4.6m2 92m2 276m2 ~70m3 ~1400 m3 4,200m3 single rotor e.g. 1.2m diameter, with 1.4m 2 2 3 Alstom TGL (0.5- socket. 15m deep. (1.53m x 3) (4.6m x 20) (70m x 20) 2MW)

Twin rotor tower e.g. 7 Steel tripod 3 x 2.2 m 14.7m2 103m2 309m2 ~230m3 ~1610m3 4,830m3 MCT (1.42-3MW) diameter pin piles with 2 2 3 2.5m rock sockets. 15m (4.9m x 3) (14.7m x 7) 230m x 7 deep.

Multiple rotor 8 Up to 6 pin piles of up to 15m2 120m2 360m2 ~225m3 ~1800m3 5,400m3 buoyant platform 1.6m in diameter with 2 2 3 e.g. Tidal Stream Ltd 1.8m socket. 10 to 15m (2.5m x 6) (15m x 8) 225m x 8 deep. (1.25-6MW)

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Monopile foundation

5.5.15 Monopiles may also be utilised and are generally larger than pin piles due to the imposed on a single pile extending between 10 – 20m above the seabed. Monopile foundations may range in size between 2m and 4m diameter with up to 2 monopiles to support a single device (such as the transverse axis device). Figure 5.19 shows an axial flow device (e.g. Voith) with a monopile foundation.

Figure 5.19 - Seabed mounted device on monopile foundation (Image source Voith Hydro).

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Table 5.9 - Parameters of monopile foundations (worst case monopile highlighted yellow).

Device type Max No. of Foundation structure Device Array Max Drill arisings Drill arisings Max. drill devices per footprint (m2) footprint (m2) development per device per array (m3) arisings in berth (not site footprint (m3) the exceeding for each development 10MW) device type site for each device type Seabed 20 Steel monopile - 2m 3.8m2 76m2 228m2 ~60m3 ~1200 m3 3,600m3 mounted single diameter with a 2.2m 2 3 rotor e.g. Voith diameter socket. Drilled to a (3.8m x 20) (60m x 20) Hydro (0.5- depth of 10 - 15m. 2MW)

Transverse axis 10 Twin surface piercing 33m2 199m2 398m2 ~665m3 ~3990 m3 7,980m3 e.g. Kepler monopile support columns 2 2 3 3 up to 4m diameter each with (16.6m x 2) (16.6m x 12 ~332m for each (~332m x 12 (limited to (1-3MW) 4.6m diameter sockets. columns*) column, with 2 columns) 20MW) Drilled to a depth of 20m. columns *note that 12 required for one Monopiles will be shared columns are device giving between devices in a row required to ~665m3 rounded configuration. WC assumes support 10 up 2 rows of 5 devices each = devices. 12 monopiles.

Multiple rotor 8 Monopile - 3m diameter with 9.6m2 76.8m2 230.4m2 ~110m3 ~880m3 2,640m3 buoyant platform a 3.5m diameter socket. 2 3 Drilled to a depth of 20m. (9.6m x 8) (110m x 8) (1.25-6MW)

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Anchor systems

5.5.16 Floating device types utilise a buoyant support structure on which to mount the TECs (see Figure 5.20). These can have a surface piercing superstructure (e.g. ScotRenewables (see Section 5.4) or be held in a submerged, mid water column position (e.g. SME). This section focuses on the description of the anchors or seabed fixing of these devices.

5.5.17 Twin rotor floating device types utilise catenary moorings and may typically require four gravity anchors, each of up to 300 tonnes, to which the mooring lines are attached. Gravity foundations for larger floating platforms may be up to 2000 tonnes with a footprint of up to 360m2. An example of this platform type is provided in Figure 5.20 below.

5.5.18 An anchored mid water column device (e.g. SME, shown in Figure 5.21) utilises a tension mooring system and is therefore subject to less movement, typically using 4 anchor points (see Figure 5.22).

Figure 5.20 - Example of surface floating device with catenary moorings (Image source: Scotrenewables).

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Figure 5.21 - Example of mid water floating device with tension moorings (Image source: www.sustainablemarine.com).

Figure 5.22 - Example of catenary and tension mooring system for floating platforms. 5.5.19 Devices utilising a catenary mooring system may cause an area of the seabed to be ‘swept’ by the mooring catenary as the device moves within a window due to external forces (wind, waves and tides). In these instances, the swept area may be up to 9500m2 (per device), significantly greater than the footprint of the gravity anchors, themselves. This does not affect tension moorings as the lines do not drag on the seabed.

5.5.20 A combination of the gravity anchor footprint and the catenary mooring means this type of device provides the worst case scenario for impacts associated with seabed footprint. As discussed previously, in order to limit the potential impacts of PTEC, a maximum of two berths could be taken up by this type of device. The worst case scenario for PTEC as a whole, in terms of seabed footprint, is based on two of the largest (10MW) berths having floating devices (e.g. Bluewater), with a footprint of 80,000m2 per berth (anchors and chain catenary; Table 5.10), and the remaining 10MW having the next largest footprint (see gravity base worst case scenario in Table 5.7).

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Table 5.10 - Foundation details for floating platforms (worst case anchored highlighted yellow).

Device type Max No. of devices Foundation structure Device footprint (m2) Array footprint Max. development site per berth (not (m2) footprint for each device exceeding 10MW) type

Twin rotor 7 Four, gravity based anchor blocks, 4 x gravity anchors (15 x 69,020m2 138,040m2 floating e.g. each weighing c.a. 300 tonnes in 6m) = 360m2. (0.07km2) Scot- water. Anchors positioned 220m (limited to 20MW) Renewables (Up and downstream) and 75 m Footprint from catenary 2 laterally from device. Catenary sweep = 9500m (1.42-3MW) mooring lines connect each of the four anchor blocks to the underside Total device footprint = 2 of the hull of the device. 9860m

Twin rotor 10 Four gravity based anchor blocks. Total device footprint = 80,000m2 160,000m2 floating e.g. Catenary mooring lines connect 8000m2 (0.08km2) Bluewater each of the four anchor blocks to (limited to 20MW) the underside of the hull of the (1-3MW) device.

Footprint is a scaled down estimate based on Scotrenewables (above).

Twin rotor mid 20 Four main mooring lines connect 8.04 m2 160.8m2 482.4m2 water buoyant the device to screwed or drilled pile 2 e.g. SME anchor points. (4 x 2.01m )

(0.1 – 2MW ) Moorings are in tension and so there is no catenary footprint.

4 x 1.6m diameter pin piles.

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Any devices/arrays with foundation footprints or drill arisings that fall within the worst case scenarios outlined below are considered to be within the Rochdale Envelope of this EIA:

• The worst case scenario for seabed impact is based on two 10MW berths of floating devices (e.g. Bluewater): o An array footprint of 80,000m2 (10 x 1MW devices); o The number of berths with this device type is limited to two to restrict the potential impact; giving o A footprint across 2 berths of 160,000m2 (20 x 1MW devices). • To complete the worst case scenario for tidal devices in the development site, the remaining 10MW could have the next largest seabed footprint of 8000m2 (20 x 0.5MW gravity base foundations); • Giving a total PTEC development site footprint from devices of 168,000m2 at any one time (0.17km2, 3.4% of the development site); • The maximum weight of the tidal device foundations is 30,000,000kg • Repowering of large arrays such as these could occur once throughout the duration of the project. Repowering will involve the removal of devices and deployment of new devices. Chapter 12, Benthic Ecology considers the likely recoverability of the seabed ecology following repowering; • NOTE: Footprints associated with construction / installation activities and ancillary infrastructure are considered in Sections 5.8 and 5.9respectively; • The maximum volume of drill arisings for the 30MW development site is estimated at up to 9780m3: o Based on 2 x 10MW arrays of transverse axis device types with drilled monopile columns (2 x 3990m3); o Plus the remaining 10MW installed with up to 6 pin piles for the buoyant platform device type (e.g. Tidal Stream Ltd), giving ~1800m3 for a 10MW array. • The maximum weight of drill arisings is 9,780,000kg

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5.6 Superstructures

5.6.1 The PTEC development site may incorporate surface piercing elements, visible above the sea surface, such as:

• Surface piercing superstructure of the devices; • Electrical hub (up to three in total), either surface piercing or submerged with a marker buoy;

• Communication and marker buoys associated with submerged devices; and • Navigation buoys (up to six, including 4 cardinal buoys and 2 special mark buoys).

As outlined in Section 5.1, principles have been developed to define the impacts of surface piercing infrastructure at PTEC:

• Each surface piercing device type (e.g. surface piercing floating, surface piercing platform or surface piercing monopile) could be present in up to two berths; and • All berths could be taken up by surface piercing device types; • If all berths are taken up by surface piercing device types there will be a maximum of 30 devices across the development site; and • If all berths are taken up with submerged devices there could be a maximum of 60 devices and each may have a small .

5.6.3 The proximity of the above devices to shore is dependent on the bathymetry and water depths in which the devices are designed to operate. Bottom mounted surface piercing devices (such as SeaGen or Kepler) typically operate closer to shore in maximum water depths of 40m mean sea level (MSL) in comparison to fully floating devices typically requiring a minimum water depth of 40m.

5.6.4 Fully floating platforms are liable to movement during changes in the tide; the extent of the movement will be dependent on the anchor method adopted. Floating devices may move by up to 80m (±40m about neutral position) around the anchor point(s).

5.6.5 In addition to the tidal devices, up to three electrical hubs may be utilised across the development site. It is expected that these will be subsurface, seabed mounted, typically up to 5 to 8 m above the seabed. Buoys may be present on the surface to accommodate radio communication devices to maintain communication with the shore in the event the fibre optic connection was to fail. These are discussed in further detail in Section 5.9. Surface piercing hubs may also be used; these would generally be monopile structures, 2m to 3m in diameter, and up to 18m above LAT (Table 5.11).

5.6.6 Navigation and marking buoys are discussed in more detail in Section 5.8. Navigational Safety Zones are discussed in Section 5.12 and in further detail in Chapter 19, Shipping and Navigation.

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Table 5.11 - Surface piercing details (worst case highlighted yellow).

Device type Max No. of Device structure Maximum height devices per above sea surface berth (not exceeding 10MW)

Twin rotor floating 10 Floating hull – height of 3.5m (including 3.5m (above sea e.g. Scot- radio antenna), length of 65m and diameter surface) Renewables, of 4m. 80m of movement around the anchor Bluewater (1 - points. 3MW)

Multiple rotor 8 The two surface piercing elements (‘spar 5m (above sea buoyant platform buoys’) are 4 to 5m above LAT with a cross surface) e.g. Tidal Stream section of 7mx4m. Ltd (1.25 – 6MW) Swings around the central anchor with a radius of 60m.

Twin rotor tower 7 The twin 1MW drive trains are mounted at 18m (above LAT) each end of a cross-beam 30m long (overall MCT (1.42 – 3MW) length including rotors is 50m) which in turn is supported by a surface piercing tubular steel tower, up to 5m in diameter and 18m high.

The form of the structure and maximum height would change temporarily during periods of maintenance with the narrow lift legs rising to approximately 40m when the cross beam and rotors are raised above the water.

Transverse axis 10 Twin surface piercing 'rotor support 18m (above LAT) columns' (2 - 4m diameter each). Support Kepler (1 – 3MW) (12 support columns are spaced 60-90m apart, support columns) the (10m diameter x 60m long) rotor.

The columns are surface piercing and could be as much as 15 - 18m above LAT.

A row of 5 devices will share support structures giving 6 columns in total.

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The following summary outlines the number and type of surface piercing devices which could be present across the development site and therefore within the Rochdale Envelope of this EIA:

• The maximum number of each device type is dependent on its capacity. As a result of the detailed principles described previously, the maximum number of each surface piercing device type in the largest berth is as follows; note the capacity will not exceed 10MW per berth: o 10 x 1MW twin rotor floating devices (e.g. Bluewater); o 7 x 1.42MW twin rotor tower (e.g. SeaGen); o 8 x 1.25MW multiple rotor buoyant platform (e.g. Tidal Stream Ltd); o 10 x 1MW transverse axis devices with a maximum of 12 surface piercing support columns (e.g. Kepler); • The development site could be composed of any combination of these different device types with each type installed in a maximum of 2 berths; • Other surface piercing device types could be installed in the remaining berths; • The maximum number of surface piercing devices across the development site is 30, or 27 for device types with height above LAT of 18m; • The maximum number of submerged devices across the development site is 60, all of which could have a small surface marker buoy.

In addition to surface piercing devices there will be additional surface piercing offshore infrastructure (e.g. buoys, see Section 5.17).

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5.7 Array Layout and Spacing

5.7.1 The development site will be split into a number of berths, providing developers dedicated access to an area to facilitate demonstration of their respective tidal device. This berth arrangement provides the necessary flexibility for PTEC to be commercially viable.

5.7.2 Dependant on developer requirements, the development site may be segregated into 3 to 6 berths. Each berth will provide a connection point for the developer to connect to the grid via a subsea export cable(s) allowing the energy generated to be exported.

5.7.3 The configuration of the arrays within the berths will be dependent on a number of factors, including metocean conditions, ground conditions (substrate type, depth, slope, etc.), and environmental issues among others. The final array layout will be identified post consent, following the berth selection process. The final detailed device locations will be developed based on further site investigation works conducted post consent to determine detailed construction constraints.

5.7.4 As discussed previously, arrays will be located within dedicated berths. In general, devices/arrays will be configured to maximise energy yield and as such are installed perpendicular to the predominant tidal flow and hence the most energetic currents. Tidal currents at PTEC predominately flow approximately 70 / 250 degrees to British National Grid North, hence tidal devices/arrays are expected to be installed perpendicular to the flow along a 160 / 340 degree orientation.

5.7.5 Bottom mounted device types could have spacing range of 20m to 300m between centres perpendicular to the flow, 100m to 600m parallel to the flow for optimum energy capture (see Table 5.12), with typical spacing of approximately 70m to 100m between centres perpendicular to the flow, and 180m to 240m parallel to the flow. Ground conditions at PTEC (geology, bathymetry) may result in devices being spread out further than specified in the table for foundation construction to be viable.

5.7.6 Floating device types commonly share anchors. For such devices, spacing may be up to 250m between structure centres perpendicular to the flow, 400m parallel to the flow. Each floating device could move by up to 80m in the direction parallel to the flow, and 60m in the direction perpendicular to the flow (see Table 5.12).

5.7.7 Table 5.12 provides estimates of the device spacing and range of movement for each device type as well as the plan area taken up by a device and the array area for the maximum array sizes (10MW). On the basis of this spacing information, Figure 5.23 to Figure 5.33 provide indicative array layouts which were used to calculate the array areas shown in Table 5.12. The maximum array areas are used in the impact assessment where applicable and the impact assessments take account of the potential for devices to be located anywhere within the development site. The actual layout and spacing for each berth will be largely defined by ground conditions and the depth requirement of the device. The location of arrays within the development site will not be known until the berth selection process is completed and therefore no location is shown for the indicative layouts. Each layout is presented at a 1:10,000 scale along with a diagram of a single device.

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Table 5.12 - Array spacing and areas.

Device Device Device Max No. of area area per area Area devices Likely (m2) 10MW per Device Likely spacing encompassing Array area per berth downstream Surface (see array 10MW Device type capacity perpendicular array (m2) (see (% of dev. (not separation movement Figure (device array (MW) to the flow (m) Figure 5.23 to site) exceeding (m) 5.23 to area x (% of Figure 5.33) 10MW) Figure no. dev. 5.33) devices) site) Floating superstructure 140m – 300m Twin rotor 140m (devices moves by 35m (devices buoyant mid would likely (within area 0.1-2.0 20 would likely 17343 346860 6.94% 874007 17.48% water (e.g. share encompassed share SME) moorings) by anchors) moorings) (see Figure 5.23) Ducted axial flow (e.g. 0.5-1 20 100m – 200m 20m – 80m No movement 344 6880 0.14% 581327 11.63% Clean current)

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Device Device Device Max No. of area area per area Area devices Likely (m2) 10MW per Device Likely spacing encompassing Array area per berth downstream Surface (see array 10MW Device type capacity perpendicular array (m2) (see (% of dev. (not separation movement Figure (device array (MW) to the flow (m) Figure 5.23 to site) exceeding (m) 5.23 to area x (% of Figure 5.33) 10MW) Figure no. dev. 5.33) devices) site) Floating superstructure moves ±40m 150m between in direction of 220m Twin rotor floating flow, ±30m staggered floating (e.g. superstructures perpendicular 1.42-3.0 7 (based on 35162 246134 4.92% 333270 6.67% Scot- (based on to flow (within sharing Renewables) sharing area anchors) anchors) encompassed by anchors) (see Figure 5.25) Floating superstructure moves ±40m 115m between in direction of 170m floating flow, ±30m Twin rotor staggered superstructure perpendicular floating (e.g. 1.0-1.5 10 (based on 19331 193310 3.87% 264472 5.29% (based on to flow (within Bluewater) sharing sharing area anchors) anchors) encompassed by anchors) (see Figure 5.26)

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Device Device Device Max No. of area area per area Area devices Likely (m2) 10MW per Device Likely spacing encompassing Array area per berth downstream Surface (see array 10MW Device type capacity perpendicular array (m2) (see (% of dev. (not separation movement Figure (device array (MW) to the flow (m) Figure 5.23 to site) exceeding (m) 5.23 to area x (% of Figure 5.33) 10MW) Figure no. dev. 5.33) devices) site) Ducted axial 160m – flow (e.g. 1.0-2.0 10 30m – 130m No movement 336 3360 0.07% 228207 4.56% 320m OpenHydro) Seabed mounted single rotor 0.5-2.0 20 180m – 360m 35m - 140m No movement 234 4680 0.09% 174525 3.49% (e.g. Voith or Alstom) 3 rotor seabed 200m – 400m 100m – 300m mounted (between 1.42-3.0 7 (between No movement 1478 10346 0.21% 167814 3.36% platform (e.g. frame frame centres) TEL) centres) Multiple rotor Device moves buoyant in 60m radius platform (e.g. 1.25-6.0 8 200m – 400m 120m – 250m about anchor. 11473 91784 1.84% 160637 3.21% Tidal Stream (see Figure Ltd) 5.30) Device will Transverse share axis (e.g. 1.0-2.4 10 400m – 600m monopiles (no No movement 657 6570 0.13% 146487 2.93% Kepler 60m lower limit on rotor length) separation)

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Device Device Device Max No. of area area per area Area devices Likely (m2) 10MW per Device Likely spacing encompassing Array area per berth downstream Surface (see array 10MW Device type capacity perpendicular array (m2) (see (% of dev. (not separation movement Figure (device array (MW) to the flow (m) Figure 5.23 to site) exceeding (m) 5.23 to area x (% of Figure 5.33) 10MW) Figure no. dev. 5.33) devices) site) Twin rotor tower (e.g. 1.42-3.0 7 200m -400m 90m - 200m No movement 745 5215 0.10% 135451 2.71% SeaGen) Device will Transverse Unlikely to be share axis (e.g. more than 2.5-3.0 4 monopiles (no No movement 1480 5920 0.12% 5937 0.12% Kepler 90m one ‘row’ at lower limit on rotor length) PTEC separation)

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Anchor

TEC

Anchor moorings

Figure 5.23 – Indicative layout of a 10MW array of twin rotor buoyant mid water device types e.g. SME used to estimate approximate array area.

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TEC (ducted rotor)

Support structure

Figure 5.24 - Indicative layout of a 10MW array of ducted axial flow device types e.g. Clean Current used to estimate approximate array area.

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Anchor TEC

Anchor mooring

Figure 5.25 - Indicative layout of a 10MW array of twin rotor floating device types e.g. Scotrenewables used to estimate approximate array area.

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Anchor Anchor mooring

TEC

Figure 5.26 - Indicative layout of a 10MW array of twin rotor floating device types e.g. Bluewater used to estimate approximate array area.

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Support TEC structure (ducted rotor)

Foundations

Figure 5.27 - Indicative layout of a 10MW array of ducted axial flow device types e.g. OpenHydro used to estimate approximate array area.

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Support structure TEC

Foundations

Figure 5.28 - Indicative layout of a 10MW array of seabed mounted single rotor device types e.g. Voith or Alstom used to estimate approximate array area.

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TEC

Support structure

Foundations

Figure 5.29 - Indicative layout of a 10MW array of three rotor seabed mounted platform device types e.g. TEL used to estimate approximate array area.

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Support Movement structure area

Foundation

TEC

Figure 5.30 - Indicative layout of a 10MW array of multiple rotor buoyant platform device types e.g. Tidal Stream Ltd used to estimate approximate array area.

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Foundations

TEC

Figure 5.31 - Indicative layout of a 10MW array of transverse axis device types e.g. Kepler (60m rotor length) used to estimate approximate array area.

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Support structure

TEC

Foundations

Figure 5.32 - Indicative layout of a 10MW array of twin rotor tower device types e.g. SeaGen used to estimate approximate array area.

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Foundations

TEC

Figure 5.33 - Indicative layout of a 10MW array of transverse axis device types e.g. Kepler (90m rotor length) used to estimate approximate array area.

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The following summary outlines the likely worst case spacing and device areas based on indicative layouts. These parameters are therefore within the Rochdale Envelope of this EIA:

• Bottom mounted device types likely spacing of 20m to 300m between centres perpendicular to flow; • Bottom mounted device types likely spacing of 100m to 600m parallel to flow; • Floating device types likely spacing of up to 250m between structure centres perpendicular to flow; • Floating device types likely spacing of up to 400m parallel to the flow; • Floating platforms within a berth would likely share moorings; • Floating platforms will move about their foundations in a defined footprint on the water surface; • The maximum area of an array is 0.87km2; • The total maximum area taken up by arrays is 2.62km2, based on: o 60 twin rotor buoyant mid water device types e.g. SME across the 30MW development site

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5.8 Other Design Considerations

Corrosion protection and antifoulants

5.8.1 The majority of devices will utilise some form of corrosion protection system; those proposed are broadly similar to those adopted within other marine industries. These may include systems such as:

• Offshore grade protective paint systems

• Impressed current systems • Sacrificial anodes

5.8.2 Abrasion resistant epoxy or acrylic paint will typically be used in the subsea and splash zones of devices. Glass flake epoxy paint is often used in the splash zone of marine structures due to its resistance to mechanical damage and its high corrosion resistance. Devices are each expected to use between 500 and 1,200 litres of paint.

5.8.3 Quantities of protective paint are generally less than 1,000 litres per device, however larger floating platforms may require up to 1,200 litres (per platform). All protective coatings and paints used will be suitable for use in the marine environment and, where necessary, approved by the Health and Safety Executive

5.8.4 Impressed Current System (ICS) or sacrificial anodes are both commonly used on ships and sub-sea structures. Sacrificial anodes are commonly used to supplement the ICS as a back- up, or located on parts of the structure where ICS cannot be used. The anodes are standard products for offshore structures, which are welded onto the steel structures and consist of Aluminium (98- 96%) and Zinc. The number and size of anodes will vary dependent on device design.

5.8.5 Antifoulants are used on the rotors and local areas of concern to prevent marine growth; they are also commonly used on the subsea structure to protect against colonisation by marine organisms. Antifoulants are generally applied in areas particularly susceptible to the build-up of marine growth such as rotors, nacelle and heat exchangers to ensure the device maintains optimum performance.

5.8.6 The majority of antifouling paints produced in the UK are copper-based, in which the main biocide is cuprous oxide, the natural form of copper. The paints also contain other biocides in smaller quantities, known as booster biocides, and these include Zinc Pyrithione, Dichlofluanid and Zineb. There are also a variety of paints that are made up with a biocide called cuprous thiocyanate, which contains a less potent form of copper and these can be referred to as ‘copper free’ paints. However, cuprous thiocyanate-based antifouling paints are generally not as effective or long lasting as the copper-based biocides.

5.8.7 The cuprous oxide leaches out over time, along with the binder, leaving a honeycomb like coating that needs to be removed once every few years.

5.8.8 A teflon based antifoulant (such as Intersleek 900) is also commonly used on tidal devices. Intersleek 900 is a non-leaching antifoulant that works by physically preventing species attachment as opposed to having biocidal activity. Antifoulant products are generally installed before the first deployment and may be reapplied as required during maintenance activities. A decision on what presents the Best Practicable Environmental Option (BPEO) will be made

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at the construction stage and may vary between devices.

5.8.9 Only biocides approved under the Control of Pesticides Regulations 1986 or the Biocidal Products Regulations 2001 for use in anti-fouling coatings may be used. A recent review of booster biocides resulted in approval being granted for the continued use of 4 substances in anti-fouling coatings. All protective coatings will be suitable for use in the marine environment. Prior to construction a detailed inventory will be submitted to the MMO.

Acoustic Doppler Current Profilers

5.8.10 A number of Acoustic Doppler Current Profilers (ADCPs) will be deployed across the development site to measure current flow speeds and directions. Each ADCP would be a bottom mounted unit, deployed in a stainless steel seabed frame. PTEC Ltd currently anticipates providing up to three units with a diameter of approximately 1.5m and a seabed footprint of approximately 7m2 each. A further 3 units (1 per berth) may be provided by the tenants themselves.

Figure 5.34 - Example of a seabed mounted ADCP and frame. (Image source: www.intoceansys.co.uk)

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Lighting and markings

5.8.11 The exact location, number and nature of the marking and navigation buoys will be determined through consultation with the Maritime and Coastguard Agency (MCA) and navigation stakeholders. Buoys will be provided in accordance with International Association of Marine Aids to Navigation and Lighthouse Authorities (IALA) standards. In the interests of including lighting and marking in each impact assessment (e.g. seascape), the following assumptions have been made based on the IALA recommendations 0-139, with Chapter 19, Shipping and Navigation, and Appendix 19A Navigation Risk Assessment considering the requirements in more detail:

• Four Cardinal buoys positioned to the north, south, east and west of the development site; and • Two Special Mark buoys.

5.8.12 An indicative layout of cardinal buoys and special mark buoys are shown in Figure 5.35.

5.8.13 Cardinal buoys will be required to have flashing white lights with a visibility of not less than 5 nautical miles. Special Mark buoys to have flashing yellow lights with a visibility of not less than 5 nautical miles. Figure 5.36 and Figure 5.37 provide an example of the style of device marker buoy and cardinal and special mark buoys proposed at PTEC respectively.

Figure 5.35 - Anticipated aids to navigation for PTEC.

5.8.14 The layout options being considered at PTEC may include combinations of surface piercing and fully submerged devices. As such appropriate consideration will be required to ensure that the method and type of marking is appropriate for the device types and build outs that take place.

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5.8.15 Fully submerged devices and electrical hubs are likely to have some form of marker buoy to assist with access, communications and retrieval. A typical marker buoy would be approximately 1.2m in diameter with a focal height of 1.5m, similar to that shown in Figure 5.36.

Figure 5.36 - Example of a device marker buoy. (Image source: http://www.hydrosphere.co.uk)

5.8.16 Cardinal and special marker buoys would typically be anchored by a concrete weight no more than 2m in diameter, with a chain catenary in contact with the seabed of no more than 30m, resulting in a total footprint, including chain drag of approximately 1,725m2 per buoy.

Figure 5.37 - Examples of special mark and cardinal marker buoys (Image source: http://www.mendezmarine.co.uk &http://www.jfcmarine.com respectively).

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Liquid inventory

5.8.17 Table 5.13 below details the types of fluids used in tidal devices. Not all devices use all of the fluids listed in the table. Many of the devices with grease or oil lubrication will use an automated lubrication system.

Table 5.13 - Liquid inventory.

Liquid type Location Volume Containment

(litres per device)

Main bearing grease 30 – 60, (up to 360 litres total for devices with multiple small TECs)

Gearbox oil 600 – 1,200

Gearbox seal fluid 30 – 60

Within enclosed Hydraulic brake fluid 200 – 450 structure such as Typically sealed using nacelle, monopile, or multiple seals within Pitch system gearbox oil 20 – 40 contained within structures or within exposed drive train exposed components Pitch bearing grease 25 – 50 components

Hydraulic fluid for yaw system ~ 1,200

Hydraulic fluid for raising and 800 – 1,500 lowering of rotor(s)

Oil for mooring winches ~ 150

Transformer oil 500 – 1,000

5.8.18 Subsea hubs that include a transformer will include up to 2,000 litres of transformer oil. Hubs may also incorporate a hydraulic system for activating winches and locking mechanisms, which would require up to an additional 400 litres of hydraulic oil within them.

5.8.19 Liquids will be contained within sealed equipment, however leaks may occur, with a maximum loss of liquid equivalent to the volumes given above.

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In addition to the device footprints, the following worst case scenario footprints for the development site will be used in the impact assessment:

• Navigational markers, 10,350m2 o 6 buoys o Anchors = 2m diameter o Catenary = 30m length x 8m drag o Footprint per anchor of 1725m2 o A maximum total weight of 200,000kg

• Monitoring equipment (ADCP), 42m2 based on o A maximum of 3 installed for PTEC Ltd o A maximum of 3 installed by tenants o Worst case footprint per ADCP of 7m2 o A maximum total weight of 600kg

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5.9 Offshore Electrical Infrastructure and Cabling

Tidal energy convertor electrical infrastructure

5.9.1 Most devices will export grid compliant power at 6.6kV or 11kV via a converter, a step-up transformer from generator voltage (typically 690V), switchgear and three-phase (wet or dry mate) connectors mounted in the nacelle of the TEC.

5.9.2 Multiple TEC platform devices generally aggregate output from all TECs (at generator voltage) and step up the voltage with a single transformer located in the platform or within an active subsea hub.

5.9.3 Electrical studies at PTEC have concluded a single export cable will be provided per berth, rated up to 6MW at 11kV (in the event of 6MW to 10MW berths, two cables will be utilised as a pair). Export cable details are discussed in further detail later in this section.

5.9.4 Some devices may have some energy storage in the form of batteries, commonly lead acid type, for operation of auxiliary systems. These systems are generally small.

5.9.5 During operation, some of the energy harnessed from the tidal flows will be lost as heat energy. In general, existing technology utilises passive cooling, exploiting the flow of water around the surface of the device to cool passive heat sinks. It is assumed that the equivalent of five percent of the harnessed energy is dissipated as heat within the tidal flow surrounding the machines and export cables. The amount of heat generated will be related to electrical energy generated and hence will increase with increasing tidal currents. It is estimated PTEC will dissipate approximately 1.5MW of heat energy during peak generation at peak tidal velocities.

5.9.6 In general, devices require a small amount of auxiliary power to run winches, hydraulics and communication systems, etc. Power will also be required to energise transformers and generators during short periods associated with start-up and stand-by. Supply of electrical power through additional (low voltage) cores within the export cable will be included. TECs will also on occasion import power through the main cores. This import or 'reverse' power flow would typically be between 20kW and 50kW per device.

Electrical hubs

5.9.7 Electrical hubs may be required at berths as a means to enable tenants to connect multiple devices to the berth export cable(s). It is expected that approximately half of the potential developers will utilise hubs.

5.9.8 In some instances these hubs are provided within one of the tidal devices, or on board a multi-device platform, negating the need for an external electrical hub.

5.9.9 Alternatively, devices may adopt a ‘daisy chain’ approach, enabling multiple devices to be connected ‘in series’, ultimately connected to the berth export cable(s). This approach is device specific, and some developers do not use this approach.

5.9.10 In most cases, where an electrical hub is required, it is expected that the hub will be located on the seabed, however it is possible that some tenants may prefer a surface piercing hub for easier access. This may be mounted within a surface piercing device (e.g. SeaGen or Scotrenewables) or be mounted on a monopile similar to those used for some devices (as

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described in Section 5.5). Both these options allow connections to be made in the dry (a dry- mate connection). Subsea hubs generally utilise ‘wet mate’ connections allowing electrical connections to be made under water.

5.9.11 Where required, subsea hubs are likely to be static, largely cylindrical structures formed from steel, between 2 and 4m diameter, up to 8m long and weighing between 15 – 85 tonnes. Where seabed mounted, hubs will extend 5 – 10 m above the seabed, located in water depth to ensure a minimum clearance of 20m under the water surface at LAT. Foundations for hubs located on the seabed are most likely to consist of a single gravity base with a mass of approximately 200 tonnes raised above the seabed on ‘feet’. Pin piles may be used as an alternative; the chosen foundation is likely to depend on the foundation type used elsewhere in the berth by the tenant. Foundation options may consist of:

2 • Gravity base (footprint typically 25m ).

• Pin piles (up to 1.6m diameter pin piles per installation). • Monopile (between 2 and 4m diameter for a surface piercing installation).

5.9.12 Subsea hubs will be provided by the tenants; as such they will be removed at the end of a demonstration period.

5.9.13 Designs may also be available in a surface piercing monopile configuration, with the platform extending up to 10m above LAT.

Figure 5.38 - Typical Passive Subsea Hub (Image source: Wave Hub). 5.9.14 Much like the tidal devices, subsea hubs generally utilise passive cooling, exploiting the flow of water around the surface of the device to cool passive heat sinks. Active hubs that include transformers may have the transformers mounted externally to improve cooling. Up to 500kW of heat (around 5% of total exported energy) will be dissipated passively into the surrounding tidal flow during operation for a 10MW berth.

5.9.15 Potential discharges to sea and air from the subsea hubs (as well as devices) are discussed in Section 5.14.

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Table 5.14 - Electrical hub summary.

Design parameters Value

Number of hubs 3 (max)

Size 2 – 4m diameter cylinder, up to 8m long

Footprint (gravity base) 25m2

Weight (hub) 15 – 85 tonnes

Weight (gravity foundation) 200 tonnes

Heat Dissipation Up to 500kW per 10MW berth (5%)

Device communication systems

5.9.16 Typically, devices communicate with shore based infrastructure through fibre optic cables within the power for monitoring and control of device equipment. It is envisaged that each export cable will incorporate two bundles of fibres, each containing 24 individual fibres. Back-up systems will also be installed on board the TECs, utilising radio antenna or wifi standards to communicate with the shore based infrastructure; for fully submerged devices, this will be facilitated through a surface buoy.

5.9.17 Electrical hubs (discussed above) may also act as a distribution point for fibre optic communication cables used within a berth. An active electrical hub is also likely to have a backup communication system via a radio or wireless link from a surface buoy tethered to the hub on the seabed.

Inter-array cabling

5.9.18 Inter-array cables will be laid between the devices; an electrical hub may be used or multiple devices may be connected in a ‘daisy-chain’ format. Tenants would be expected to install their own inter-array cabling where more than one device is being demonstrated within a berth, and to connect their project to the export cable at its termination point.

5.9.19 Tenants will be required to ‘close the gap’ between their project (first device or hub) and the PTEC cable end with a cable owned and installed by the tenant, i.e. a ‘cable tail’, as shown in Figure 5.39.

5.9.20 The total length of inter-array cabling would be dependent on the array layout within each of the berths, dictated by geotechnical and bathymetric considerations (among others). The final length and layout of inter-array cabling will be determined by tenants prior to installation of their respective devices. The maximum array cable length for the site is based on the maximum number of berths (i.e. 6). Within each of the six berths the inter-array cabling (including the cable tail) is assumed to be no greater than 3.5km, with a typical length closer to 2km. The total inter-array cabling considered within the Rochdale Envelope is 21km.

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5.9.21 The inter-array cable voltage will be dependent on the devices and may vary between 690V (generator voltage) and 11kV, utilising a cable size of up to 120mm diameter.

5.9.22 The maximum footprint of inter-array cabling for up to six berths is therefore 2520m2.

Export cabling

5.9.23 Subsea export cables are required to connect the tidal devices/arrays to the onshore substation/control room, where the power is subsequently exported to the local distribution network. The PTEC export cables for each of the berths (up to six) will be made available at the edge of each berth, some distance away from where the tenant generators are likely to be located.

5.9.24 It is proposed that the end of the export cable for each berth would remain in a fixed place for the duration of the operational phase of the facility. Tenants would connect to the export cable with an electrical hub, connectors or cable splice.

5.9.25 The PTEC export cables will be ‘bundled’ into pairs (maximum of 3 bundles for 6 export cables), meaning that two cables supplying neighbouring berths will be flexibly bundled together with a spiral ‘strap’ before being laid as a joined pair.

5.9.26 Figure 5.40 shows an indicative layout of the export cables which takes into account the minimum spacing for the cable bundles. The cable bundles will be laid on the seabed with a minimum separation of 50m between bundles, to reduce the risk of damaging cables that have already been laid and to ease access in the event of repairs. The total export cable length on the seabed will be 23km (this is a result of the bundling; the total requirement of export cable is approximately 46km). Approximate cable lengths for three bundles of paired export cables are:

• 5.9km • 7.8km

• 9.5km

5.9.27 The cable routes within the subsea cable corridor, take account of:

• Minimum spacing requirements to avoid derating of the cables and to ease laying operations and subsequent access; • Avoiding key reef features to minimise impacts on the seabed ecology and reduce physical risks to the export cable, in particular: o Avoid or minimise crossing of slopes beyond 10 which pose risks of cable movement and damage when surface laid; ⁰ o Avoid crossing scarps, ridges, scour lines or other areas where there are rapid variations in bathymetry which could lead to damage of the cables if laid across such a feature; and

o Using appropriate cable protection to avoid cable moving around on the seabed • Following a direction which runs parallel to the flood and ebb tidal current flows to maximise lateral stability of the cable on the seafloor.

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5.9.28 Each PTEC export cable tail will be a minimum of twice the water depth (from its split out point) to allow the tenant to recover the export cable to the surface for splicing, without interfering with the export cable for the adjacent berth.

Figure 5.39 - Schematic layout of export cable connection.

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Figure 5.40 - The offshore cable routes from the termination points within each berth to the landfall point onshore.

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5.9.29 The subsea export cables are likely to be 3 core, 11kV, 240mm3, utilising copper conductors with integral insulation, core screening and steel armour for durability. The cable would incorporate a polypropylene outer sleeve with an external diameter of up to 130mm. The maximum footprint of export cabling for three bundles of paired cable is therefore 5980m2 (23,000 x 2 x 0.13).

5.9.30 An example of a typical armoured cable is provided in Figure 5.41.

Figure 5.41 - Section of a typical armoured cable (Image source: JDR Cables).

5.9.31 The export cable would incorporate fibre optics for communication with the devices. Also embedded within each cable will be a low voltage auxiliary power cable to allow the supply of power to operate auxiliary or installation equipment for devices at each berth. This is currently anticipated to consist of three 25mm2 cores.

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Figure 5.42 - Double armoured cable similar to that currently planned for PTEC

Cable protection / armouring

5.9.32 The subsea export cables will be aligned with the tidal flow as much as possible and will incorporate double armour; similar to that shown in Figure 5.42 which will protect the cables and provide ballast to stabilise the cables. No scour protection is anticipated to be required for the subsea export cables. As with the device foundations, scour at the development site is not considered to be a significant issue as the seabed is predominantly exposed bed rock and so no scour protection is anticipated to be required for the inter-array cabling.

5.9.33 Close to the shore there is an area of sediment which may allow the cables to be buried.

5.9.34 Where it is not possible to bury the cables, they may be provided with cable protection, in the form of concrete mattresses, rock bags (Figure 5.43 and Figure 5.44) or split pipe sleeves (Figure 5.45), at strategic locations along the cable length. The cables will terminate in a block anchor or rock bag / mattress. These will prevent the cable from being disturbed by the tidal flows. The size of the rock bags or mattresses is anticipated to be eight tonnes, and it is envisaged that up to 150 bags / mattresses will be required for the export cable with a combined seabed footprint of circa 1,500m2. The inter-array cabling is estimated to require a maximum of 100 bags / mattresses with a combined footprint of approximately 1000m2. The impact assessment considers that the cable protection may be placed anywhere within the offshore site, up to the maximum footprint.

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Figure 5.43 - Examples of rock bags (Image source: http://www.sps.gb.com).

Figure 5.44 - Examples of rock mattresses (Image source: http://www.sps.gb.com).

Figure 5.45 - Example of Split Pipe Sleeves (Image Source: EMEC). 5.9.35 Similar protection and armouring techniques to the export cable will be adopted for the inter- array cabling.

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The following worst case scenario features for the development site will be used in the impact assessment:

• Hubs, 75m2 based on: o A worst case footprint per hub = 25m2 o A maximum of 3 hubs across the development site o Maximum total weight 599,400kg

• Inter-array cabling, 2520m2 based on o Worst case of 3.5km per berth o Total length of 21km (6 berths) o 120mm cable diameter o Worst case footprint per berth = 420m2 o Maximum total weight of 650,000kg

• Export cables, 5980m2 based on: o A worst case total length of 23km for 3 bundles of paired cable o 130mm cable diameter o Maximum total weight of 1,500,000 (including 717,000kg in the development site and 783,000kg in the subsea cable corridor)

• Cable protection, 2500m2 o A maximum of 150 rock bags/mattresses for the export cable o A maximum of 100 rock bags/mattresses for all inter-array cabling o A maximum total weight of 1,200,000kg for the export cable protection (including 574,000kg in the development site and 626,000kg in the subsea cable corridor) o A maximum total weight of 800,000kg for the inter-array cable protection

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5.10 Cable Landfall

5.10.1 The export cable will make landfall on the Isle of Wight at Castle Cove, approximately 1km west of the centre of Ventnor. Landfall will be achieved through one of the options shown on Figure 5.27 and listed below:

• Cables trenched/buried, making landfall adjacent to the existing slipway; • Using an existing, 600 mm diameter outfall pipe as a cable duct for some or all of the export cables; or • Horizontal Directional Drilling (HDD) under the shoreline from a suitable location close to the proposed substation/control room, with cable emerging in the shallow subtidal for connection to the marine export cables.

5.10.2 A combination of the options is also a possibility, e.g. with some cables pulled through the outfall pipe and the remainder laid in an open cut trench or installed via HDD.

5.10.3 The preferred landfall option is to use a more ‘conventional’ open cut trenching method to achieve landfall alongside or possibly utilising the existing concrete slipway at Castle Cove. The trench will extend from the upper shore up to 500m seaward, to a maximum water depth of 10m. The trench will be 3 to 10m wide and 1-1.5m deep. The cable would subsequently be installed utilising an open trench method within or alongside existing access tracks / paths for approximately 250m to connect with the proposed PTEC substation/control room. On construction the trenches would be covered over and surfaces re-instated. Route options are shown in Figure 5.47 to Figure 5.51.

5.10.4 An alternative option is to use the existing, 600mm diameter, Southern Water Services Ltd emergency outfall pipe as a cable duct for the export cables. The pipe passes from the Southern Water Services Ltd land down the cliff, exiting around 90m from the shore in about 4.5m water depth, shown in

5.10.5 The cable would remain within the outfall pipe on land emerging adjacent to one of the possible locations for the proposed PTEC substation/control room. To ease installation and maintain separation of the cables, individual polyethylene (PE) ducts for each export cable will be required within the pipe – the export cables will be pulled separately through each duct. The cables would exit the pipe at the ‘last’ manhole and be trenched the remaining distance (30-50m) to the PTEC substation/control room. This option will be subject to written confirmation from Southern Water Services Ltd that there is sufficient capacity within the outfall pipe to accommodate the cables and retain the function of the outfall pipe in the unlikely event that it is required.

5.10.6 If HDD is adopted, the three HDD ducts would extend from the temporary laydown/ construction area adjacent to the proposed PTEC substation/control room for a length of between 200m and 900m from the onshore HDD location, where they would re-emerge at seabed level. The diameter of each HDD duct would be up to 0.7m. The onshore HDD locations are shown in Figure 5.49 and 5.50. The approximate worst case scenario end point (closest to shore) is shown in Figure 5.40.

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Transition pit

5.10.7 The preferred option is to terminate the subsea cables within a transition pit (or pits), at a point approximately 7m above Chart Datum, landward of the rock armouring coastal protection. Transition pits allow the offshore cables to be jointed into a more flexible onshore cable for final connection at the PTEC substation/control room. A transition pit is an underground cavity that allows the subsea cable ends to be jointed to regular onshore power cables in a safe and protected enclosure. The location of the transition pit is dependent on the landfall solution adopted. For landfall via the Southern Water Services Ltd emergency outfall pipe and via HDD, it is envisaged that the marine cables will terminate in a ‘cable basement’ below the PTEC substation/control room. If an open trench is adopted, up to two 8m x 4m transition pits may be installed on open ground above the slipway (see example in Figure 5.46). Transition pits are generally formed from reinforced concrete, installed below ground level with access provided by removable covers.

5.10.8 After the completion of the works, the transition pits would be re-covered and the site returned to its original state, leaving very little evidence of their existence other than manhole access.

Figure 5.46 - Example transition pit. 5.10.9 A key advantage of using a transition pit and onshore cables is that all of the onshore work can be carried out independently of the offshore work meaning that any delays in either works will not impact the other. This approach helps to reduce these risks and ultimately, limit the costs of the installation process.

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The landfall area for the export cables from the development site will be at Castle Cove and the onshore infrastructure location at Flowers Brook, in the vicinity of an existing Southern Water Services Ltd pumping station.

The key components of the project description in relation to landfall include:

• Landfall works by either: o Trenching; o HDD; or o Routing through an existing outfall pipe

The preferred landfall method is an open cut trench, using an excavator to dig a trench for the cables in the intertidal region and shallower waters less than 5m to 10m deep. The length of this trench is expected to be in the range of 200 to 500m, approximately 3m to 10m wide, and 1-1.5m deep.

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5.11 Onshore Infrastructure

Substation and control room

5.11.1 A substation/control room will be required to manage and facilitate the export of electricity from PTEC to the local distribution network. The substation/control room will be located within or adjacent to the existing Southern Water Services Ltd land, situated off the A3055, Steephill Road, approximately 1km west of Ventnor. The purpose of the onshore substation and control room is to:

• Receive the power generated from the devices. • Transformation of the generated power from 6.6 or 11kV to 33kV for export to the distribution network. • Control and monitoring / metering of the devices, including provision of auxiliary low voltage import power.

• Ensure compatibility of the generated power with the requirements of the Distribution network operator.

5.11.2 The onshore site is located approximately 100m inland from the coast, 15m above mean sea level. Within the onshore site there are two suitable locations for the PTEC substation/control room: in Southern Water Services Ltd land; or in the Red Squirrel Ltd land/caravan park; and these are shown in Figure 5.27

5.11.3 The scenarios in Figure 5.47 to Figure 5.48 show possible substation/control room locations. Due to discrepancies between the ordinance survey (OS) map and aerial survey imagery, Figure 5.47 to Figure 5.51 are shown on A) the OS basemap, and B) aerial imagery.

Temporary laydown/construction area and possible HDD

5.11.4 There are three temporary laydown/construction area options for the project, which are shown in Figure 5.47 to Figure 5.51 as an indication of the total area affected, however, either of these options could apply to each scenario. The temporary laydown/construction area will be reinstated once construction is complete.

5.11.5 Figure 5.49 and Figure 5.50 provide the options for HDD. Figure 5.51 outlines the option of routing through the outfall pipe. Figure 5.49 to Figure 5.51 show the short trenches that would be required from the pipe or the HDD pits to one of the substation/control room options shown in Figure 5.47 and Figure 5.48.

Onshore cabling

5.11.6 The onshore cables will be installed in a trench from the landfall location to the substation/control room as either a continuation of the foreshore trench, or a trench from the transition pit, HDD pit, or outfall pipe. Figure 5.47 to Figure 5.51 show onshore cable route options.

5.11.7 Onshore cabling from the PTEC substation/control room to the grid connection is outside the scope of this EIA and will be managed separately by SEPD.

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Figure 5.47A - Option 1, cable trenching corridor following the line of the existing track through Flowers Brook, with temporary laydown/construction area in the Council field and/or RSL land/caravan park, and the substation/control room in the Southern Water Services Ltd land, including track realignment and a parking area within the Southern Water Services Ltd land.

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Figure 5.47B - Option 1, cable trenching corridor following the line of the existing track through Flowers Brook, with temporary laydown/construction area in the Council field and/or RSL land/caravan park, and the substation/control room in the Southern Water Services Ltd land, including track realignment and a parking area within the Southern Water Services Ltd land.

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Figure 5.48A - Option 2, cable trenching within a cable corridor on RSL land/caravan park, with construction of the substation/control room, and the temporary laydown/construction and parking areas also on RSL land/caravan park.

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Figure 5.48B - Option 2, cable trenching within a cable corridor on RSL land/caravan park, with construction of the substation/control room, and the temporary laydown/construction and parking areas also on RSL land/caravan park.

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Figure 5.49A - Alternative option of HDD from RSL land/caravan park with the associated trench options from HDD to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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Figure 5.49B - Alternative option of HDD from RSL land/caravan park with the associated trench options from HDD to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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Figure 5.50A- Alternative option of HDD from the Council field with the associated trench options from HDD to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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Figure 5.50B- Alternative option of HDD from the Council field with the associated trench options from HDD to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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Figure 5.51A - Alternative option of routing through the outfall pipe with the associated trench options from pipe to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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Figure 5.51B - Alternative option of routing through the outfall pipe with the associated trench options from pipe to substation/control room location options (shown in Figure 5.47 to Figure 5.48)

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In order to define the Rochdale Envelope for the EIA, the following worst case parameters for the onshore features have been defined based on the options shown in Figure 5.47 to Figure 5.51. • Onshore cable corridor o HDD cable installation; o Cable (including trenching activities) construction footprint onshore of 3,091m² (based on the longest route, following the existing track through Flowers Brook) o Within this area, one 3m wide trench or two 1.5m wide trenches would accommodate the onshore cables (either marine or onshore cables depending on the use of transition pits) • Possible transition pit(s) for the option of changing from marine cables to onshore cables for the route from landfall to the project substation/control room o 36m² each x 2 transition pits = Total 72m2 • Substation and control room o Total area of 375m² o As either 2 separate buildings or 1 combined building o Area includes outdoor 2.4m close-boarded fenced area for transformers o Height 6.8m • Possible levelling works • Parking area o 62.5m² • Possible private road/track alterations to ensure access is maintained o 286m² • Laydown/construction area o 2522m², includes sufficient area for HDD

Substation/control room details

5.11.8 The substation/control room layout will be finalised during the procurement/detailed design phase of the project. It is envisaged that the substation/control room will incorporate the following key elements:

• A cable basement where the incoming cables will be terminated and transition jointed into standard single core power cables for onward routing around the substation/control room. • A high voltage switch room which will contain the 11kV switchboards and substation/control room batteries.

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• A pair of extra high voltage switchrooms, to house the 33kV switchboards. One switchboard would be owned by SEPD and one by PTEC Ltd, each in their own room. • An outdoor compound, which will contain the main 33/11kV transformer and associated earthing equipment. This will also contain separate 6.6/11kV ‘berth transformers’ as necessary as well as station transformers for tenant auxiliary power and local LV supplies. HV harmonic filters and additional reactive plant will be included as necessary. This is currently estimated to be sets of harmonic filters to address two separate harmonics. • A panel room, containing Supervisory Control and Data Acquisition (SCADA) racks, Local Area Network (LAN) and Wide Area Network (WAN) equipment, breaker remote control panel, LV distribution board(s), intruder alarm panel, fire alarm panel, etc. • A metering room, adjacent to the 33kV switchrooms, accessible to the meter operator, for revenue metering of the whole development site. • A shared control room, housing a control desk for the PTEC system, as well as control desks and cabinets for tenant systems, allowing operators to monitor and control their offshore equipment from the control room or remotely. Sub-metering panels for each berth will also be housed in the control room. • Welfare facilities for operational staff based at the facility.

5.11.9 Indicative plans for a combined substation/control room or two separate buildings are shown in Figure 5.52 and Figure 5.53 respectively.

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Figure 5.52 - Indicative combined substation/control room layout.

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Figure 5.53 - Indicative substation and control room layouts.

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5.11.10 The substation/control room building(s) is envisaged to have a footprint of up to 375m2 with a maximum roof height of 6.8m above adjacent ground level. The substation/control room building is currently anticipated to be a conventional single storey brick clad masonry building which, for durability and aesthetic reasons (see Chapter 16, Seascape Landscape Visual Impact Assessment), will be in keeping to the nearby Southern Water Services Ltd pumping station design, founded on a concrete foundation. A steel portal frame structure with colour bond type cladding may be considered if appropriate. Piling may be required to support the weight of the transformers.

5.11.11 The outdoor compound will contain the main 33/11kV transformer and associated earthing equipment and be surrounded by a fence. Siting of the outdoor equipment will aim to be as unobtrusive as possible (e.g. behind the substation/ control room building and/or screened as appropriate). This will also contain separate 6.6/11kV ‘berth transformers’ as necessary. Transformers for tenant auxiliary power and local low voltage supplies will also be located in this compound as will high voltage harmonic filters or other power quality equipment as necessary. The outdoor compound will comprise a concrete base, bunded to the equivalent of the transformer internal volumes and with the drain facilities arranged in accordance with the requirements of the Environment Agency. Any other outdoor oil filled equipment will also be bunded.

5.11.12 Vehicular access to the onshore site will be provided by the existing access tracks from the A3055 main road. Minor improvements to these access tracks may be required with additional permanent hard standing for parking of up to 7 vehicles.

Control room

5.11.13 The control room will be a shared facility at which the import/export power system is monitored and controlled.

5.11.14 The control room will be equipped with control desks to be fitted out and equipped by the tenants and will enable operators to monitor and control their equipment. This room will also house the PTEC control system. Each tenant will be allocated rack / cabinet space within the panel room for the installation of their own racks. Arrangements for remote monitoring and control of tenant’s offshore equipment will be provided in the form of a dedicated high speed broadband connection to the control room.

5.11.15 The substation may also provide the facility for some tenants to locate their power converters onshore.

Grid side connections

5.11.16 PTEC is responsible for the provision and installation of ducts and / or trenches within the boundary of the onshore site for use by SEPD in their connection works. The outgoing 33kV connection to the distribution network will be routed, by means of either a precast concrete trench or directly buried in the ground, to the perimeter of the substation/control room compound.

5.11.17 Cabling and enabling works will be required to connect the PTEC substation/control room to the existing SEPD substation at Wootton Common, approximately 20km to the north. Cabling

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works ‘grid side’ of the project substation/control room and any further enabling works at Wootton Common will be undertaken by SEPD and as such fall outside of the scope of this ES.

5.12 Construction Methodology

5.12.1 This section covers construction within the offshore site, at the cable landfall, and the onshore site.

Offshore construction

5.12.2 Offshore construction will include the following principle activities:

• PTEC Ltd works

o Installation of export cables o Placement of cable protection o Placement of navigation buoys

o Placement of site monitoring equipment • Tenants works o Foundation construction: . Drilling; . Gravity base placement with possible ground preparation; or . Anchors (drilled or gravity base).

o Support / superstructure and TEC installation o Installation of inter-array cables o Installation of electrical hubs (if required)

o Placement of cable protection o Placement of site monitoring equipment

Tidal devices

5.12.3 Due to the wide range of possible device types that may be installed at PTEC, it is not possible to specify the exact installation methodology that will be adopted. The consultation process has been used to inform the likely foundation and device installation methods that may be used at PTEC.

5.12.4 The intended construction sequence for each berth as undertaken by the tenants will be as follows:

• A vessel installs the foundation system (where piled this will likely require subsea drilling from a Dynamic Positioning (DP) vessel, or for gravity foundations a heavy lift vessel);

• A suitable vessel installs the support/superstructure;

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• A suitable vessel installs the TEC onto the foundation structure; and • A suitable vessel installs the inter-array cabling and connects to the export cable (previously installed by PTEC Ltd). 5.12.5 Depending on the device design, a number of these activities may occur at the same time. Typical installation regimes for the representative tidal technologies are outlined in Table 5.15.

Table 5.15 – Indicative device installation regimes

Representative Indicative device installation methodology technology

Alstom TGL 1. Tripod foundation deployed by moored crane barge or DP vessel. 2. Pin piles are self-drilling, controlled from a DP vessel, then grouted into place in the seabed. Installation time: 3. The buoyant TEC is towed to site using a multi-cat or DP vessel. 3 days per device 4. The nacelle is subsequently winched down to the tripod foundation.

Voith Hydro 1. The foundation pile is installed through remote drilling using a subsea rig from a DP vessel and subsequently grouted into place.

2. The device is installed using a bespoke lifting frame and guide chains from a DP Installation time: vessel with appropriate lifting capacity. 3 days per device

1. Tripod foundation together with tower and cross arm lowered onto the seabed MCT using a suitable heavy lift vessel (DP or moored). 2. Four pin piles installed through remote drilling using a subsea rig from a DP vessel, using the foundation as a template and subsequently grouted into place Installation time: (to the seabed and foundation). 3-5 days per device 3. Power-trains and rotors installed separately using an appropriately sized multicat or DP vessel.

1. Foundation frame (together with TECs) installed with a bespoke lifting frame by Tidal Energy Limited a DP or moored heavy lift vessel. 2. Floating to site and ballasting under consideration for larger system (up to

2MW) utilising a bespoke installation vessel. Installation time: less No piling necessary. than 1 day

Clean Current or 1. Seabed preparation may be required for proposed gravity foundation Open Hydro 2. Dredging equipment used to provide level area of bedrock. 3. Foundation and device installed onto seabed in single operation using either a moored crane barge or specialist DP vessel.

Installation time: ‘Feet’ may be used in future designs to minimise seabed preparation. 3 - 4 days per device

1. Support piles installed using remote drilling with subsea rig from a DP or Kepler moored vessel and subsequently grouted into place. 2. Device's rotor, generator and structure are then attached to the support structures on the surface using a vessel with similar capabilities to that of the Installation time: foundation installation vessel. 3 to 5 days per Floating columns out to site and ballasting into position using a smaller support

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Representative Indicative device installation methodology technology

device vessel also under consideration.

Scotrenewables or 1. Anchor blocks or piles, and mooring lines installed by a suitable heavy lift vessel Bluewater (DP or anchored). 2. The hull of the device is towed onto site by a typical multicat type vessel.

3. The mooring lines and umbilical are connected to the mooring turret of the Installation time: 2 to device on the surface. 3 days (including Positioning of the anchor blocks does not require high precision. mooring lines and anchor)

1. Foundations installed using remote drilling using a subsea rig from a DP vessel Tidal Stream Ltd for monopile or pin piles (with subsequent grouting), or heavy lift vessel for gravity base. 2. The buoyant Triton structure together with the TECs mounted (and tether arms) Installation time: is towed to site using at least 2 suitable tugs or multicat type vessels. 3. Once on site, portions of the support structure are flooded to alter the trim of the 3 to 4 days per device causing the structure to rotate, meaning that the connection point of the device structure 'falls' towards the seabed, aided by guide wires, so it can be attached to the foundation unit.

1. Anchor screw piles are installed, by remote drilling using a propriety subsea rig SME from a DP vessel. Convention drilled piles and grout would be used in very hard rock. 2. Mooring chains are connected to the anchors and are buoyed off. Installation time: 3. The buoyant device platform is towed to the site by a multicat type vessel, in an 2 to 3 days per unballasted state so that it floats on the water surface. device 4. Mooring lines and electrical cables are attached and four winches then pull the platform down to the correct depth and trim.

Generic drilled foundation construction

5.12.6 Drilling operations for foundation construction is generally undertaken from a DP vessel or moored crane barge. A single socket is drilled for monopoles; for multiple pinpiles, the foundation structure is generally placed on the seabed first and used as a drilling template. Table 5.16 to Table 5.20 provides indicative details of a small DP vessel that may be utilised for foundation drilling operations.

5.12.7 Some piles will be self-drilling; others will be inserted into oversized pre-drilled sockets in the seabed. The drilled depth in both cases would vary between approximately 10-25m below seabed level, dependant on device type and the strata encountered.

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Figure 5.54 - Subsea drilling apparatus launched from DP vessel (Image sources: Bauer Renewables).

5.12.8 Drill cuttings may be continually released into the water column as they emerge from the drilled rock sockets. No drilling fluids are proposed as the drilling will use seawater flush for lubrication. The level of dispersion of the drill arising will vary with size, type and water current velocities at the time of drilling. This is discussed further in Chapter 7, Physical processes.

5.12.9 Once drilling is complete, piles would be lowered into the socket and grouted into the underlying material with a cementitious non-shrink grout. Approximately 20m3 of grout will be used per pile for the majority of devices to provide a sound connection to the seabed; this could be up to 80m3 for very large piles. The foundation structure is subsequently grouted onto the piles to provide a sound connection. During this process up to 5m3 of grout will be used per pile connection, with up to 1m3 grout lost to the surrounding environment.

Generic gravity based structure (GBS) construction

5.12.10 GBS foundations do not require drilling. The majority of gravity base designs for bottom mounted systems utilise ‘feet’, raising the structure above the seabed. GBS foundations for bottom mounted devices generally incorporate the support structure and tidal energy convertor to streamline the construction process.

5.12.11 All types of gravity anchors (both bottom mounted and floating types) will be installed with a heavy lift vessel (DP or moored barge) of sufficient lifting capacity to install the foundation structure. DP vessels are generally better suited to sites with large tidal currents, being able to hold station and maintain operations during times of higher flow.

5.12.12 The maximum theoretical seabed footprint area for a large anchor barge, considering anchor spread and catenary, is up to approximately 380,000m2. This is based on the maximum possible extent of vessel movement with a single anchor set-up. In reality it is highly unlikely that an construction would require such a lot of movement from the vessel without changing anchor positions.

5.12.13 Based on an assumption of installing 5 devices from a single anchor set-up, the impacted area would be a maximum of approximately 160,000m2.

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5.12.14 Each gravity anchor will be approximately 5 to 8m in diameter (or approximate equivalent rectangular area) with 4 to 8 anchors per vessel. Giving an anchor footprint of around 200m2 to 400m2 per vessel.

Support structure and device construction

5.12.15 Methods for support structure and / or device construction vary with each device, however they generally comprise one of two methods:

• A moored crane barge or DP vessel with sufficient lifting capacity is used to transport the device from port to the installation location. Once at the site, the vessel lifts the device from the vessel deck onto the foundation structure.

• The TEC / device is floated out to site with tugs or Multicat. Once at the site, the device is ‘trimmed’, sunk or winched into position. The method of fixing the TEC to the support structure varies, however may commonly involve winching the device to the support structure and use of a locking mechanism, possibly with the use of a remotely operated vehicle (ROV) for the final connection.

5.12.16 Bespoke platforms and vessels are currently being developed by some device manufactures to simplify the construction process. Typical details of the vessel types that may be used for this purpose are provided in Table 5.16 to Table 5.20.

Export and inter-array cabling

5.12.17 Cable installation offshore is generally achieved with the use of specialist cable installation vessels with deck mounted cable carousels (turntables) to load and deploy the cable (see Table 5.18).

5.12.18 Given the length of cable (see Section 5.9) to be installed it is highly likely that a DP cable installation vessel will be used, mobilised with cable lay equipment and up to two cable carousels (turntables) with minimum capacity of 800 tonnes of cable each.

5.12.19 The export power cables will be laid along the seabed in bundled pairs with reduced separation in order to remain within the specified cable corridor. Once the cable is laid on the seabed there may be a requirement to move the cables to a more appropriate location which is free of snags/ boulders. This process may require the use of an ROV and for the purposes of the assessment it has been assumed that the subsea cables may be moved from their initial position within a corridor of up to 21 m wide. This is based on the width of the largest vessel which may be used for the cable installation.

5.12.20 Floatation buoys may be used to float each of the cables, or cable bundles, ashore from a cable-laying vessel, as shown in Figure 5.55. The cable ends will have a pulling head attached to them to allow a winching cable to be attached from an onshore winch. The cables would then be winched to the shoreline and either directly up onto the land, or through pre-laid ducts.

5.12.21 Once two cables have been sufficiently pulled-in to shore, the cable lay vessel will surface lay the two cables together, most likely through a bundling machine, working towards the offshore site. The vessel will be guided by its dynamic positioning system, or tugs to pinpoint

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the cable location. Once installation of the first bundle (consisting of two cables) has been completed, the process will be repeated for cables 3 and 4, then 5 and 6, installed as bundles.

Figure 5.55 - Floating power cables ashore from a cable laying vessel.

5.12.22 In the soft / sandy substrates near shore, export cables will be buried where possible to a depth of approximately 1m, this is largely to protect the cable from anthropogenic and the effects of wave and current induced vibrations but also to reduce the effects of electro-magnetic fields (EMF) on sensitive marine species. It is expected that sufficient sediment will be present in the first 1km of the cable route, with potential for sufficient sand accumulations to attempt burial up to 4km from shore. A jetting ROV (or possibly cable plough) will then be used to bury the cable. Jetting works by using a high- water jet to fluidize the seabed, allowing the cable to sink into the sediment under its own weight. The number of runs required is determined by seabed conditions and burial depth requirements.

5.12.23 A survey and trenching vessel may also be used to provide support to the installation vessel for pre-construction surveys and control of jetting ROV.

5.12.24 Cable landfall operations are discussed below under ‘Onshore Construction’.

Cable protection

5.12.25 As detailed in Section 5.9, the export cable will be double armoured and surface laid in parallel with the tidal flow as much as possible, avoiding areas of steep gradient and localised escarpments. The weight of the steel armouring will largely hold the export cabling in position. Additional cable protection measures may consist of rock bags, mattressing or split pipes. Rock bags or mattresses will be placed at strategic locations along the length of all cables. The installation of these will most likely be undertaken using a small (DP) vessel

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with a crane or A-frame and ROV, with bags or mattresses fed to it using up to two barges and attendant tug for each barge. Spilt pipe sleeves can be installed on the cables as they are laid from the installation vessel. In the event the full extent of cable protection is required it is envisaged it would require 25 days for a vessel to place the rock bags or mattresses.

5.12.26 It may not be possible to completely avoid crossing localised escarpments. Those instances where the cable free hangs / free spans over scarps can be addressed post-lay by either moving the cable a small amount, or by placing rock bags underneath the cable to support it and negate free hanging forces. This is illustrated in Figure 5.56. This will help prevent cable fatigue or damage from free spanning. The number and footprint of these rock bags is incorporated within the conservative estimates provided in Section 5.9.

Figure 5.56 - Example of post-lay mitigation over using rock bags under an escarpment 5.12.27 During the protection work, a post lay survey will be undertaken by the same vessel and ROV; then any remedial work (re-positioning of cables or additional bags/mattresses required) can be undertaken immediately.

Vessel requirements

5.12.28 Construction vessels and materials for the offshore installation works will largely be arriving by sea from the UK and mainland Europe.

5.12.29 Table 5.16 to Table 5.20 outline example vessels which could be used in the offshore construction process.

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Table 5.16 - Indicative details of a small DP offshore support vessel.

Variable Value

Vessel Type Small DP Offshore support vessel

Typical Example Kingdom of Fife

Picture

(Image source: Briggs Marine)

Description Small and medium sized DP offshore vessels are often used for drill support, anchor handling and inter array cable installation

Dimensions Length 61.20m, Beam 13.5m, Deck Space 300 m2

Gross Tonnage 1459te

Propulsion 2 x 2 MW Caterpillar C286-6, plus 392kW bow thruster

Lifting capacity 2 cranes each with capacity < 20te. Deck cargo capacity 500te

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Table 5.17 - Indicative details of offshore DP vessel and crane barge.

Variable Value

Vessel Type Offshore DP / Barge (moored)

Typical Giant KML BD6074 Example

Picture

Image source: Keynvor MorLift Ltd Image source: North Sea Shipping

Description Multi-Purpose Offshore Construction A relatively simple vessel offer moderate to high Vessel with sufficient deck space and lifting capabilities and deck space but well suited cranage to accommodate most to installing tidal device structures. Typically they moderate offshore infrastructure lifts. may be self-propelled or simply a ‘dumb’ barge and so may need to be positioned by tugs to deploy anchors which allow them to hold station.

Dimensions Length 160.9m, Beam 30.0m, Deck Length 42.0m, Beam 22.0m, Deck Space 400m2 Space 2900 m² Draught 6.0m Draught 2.5m

Gross 18,151te 1,246te Tonnage

Propulsion 21 MW Power. Konsberg DP III. 5 N/A (moored barge example) Voith-Schneider Units

Lifting 1x 400 t Crane, 1x 50 t Crane 150te at 20m radius capacity

Other A typical mooring spread would consist of up to Comments six moorings on a 'radius' from the vessel centre of between 500 and 800m. Overall area of mooring spread would be a rectangle of approximately 500 to 1,400m by 850 to 1,600m.

One or two support vessels generally also required, 30m x 22m to assist with positioning and anchor deployment

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Table 5.18 - Indicative cable installation vessel details.

Variable Value

Vessel Type Cable Installation Vessel (DP 2 Class)

Typical Example Team Oman

Picture

(Image source: Visser and Smit)

Description These vessels transport the spool of subsea electrical cable to the offshore site and allow the cable to be reeled off the spool and laid on the seabed as the vessel tracks along the intended cable route.

Typically used to deploy a cable plough/trencher but this is not likely to be the case at the PTEC site. An ROV may be employed during the cable lay to ensure the cable is free from snags/boulders, etc.

Dimensions Length 130.7m, Beam 21 m, Draught 7.0m

Gross Tonnage 11242 te

Propulsion 10,200 kW, 2 x Stork-Wärtsilä, including DP2 capability (2 x 1MW bow thrusters, 2 stern azimuth thrusters)

Lifting capacity 7 small cranes with capacity < 5te. Max capacity of 5,200 te of cable.

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Table 5.19 - Indicative details of rock placement vessel.

Variable Value

Vessel Type Rock Placement / Matressing Vessel

Typical Jan Steen Example

Picture Image source: Van Oord

Description Used to transport aggregate to site and place graded rock on the seabed in a controlled dumping activity. The rock is used as protection for seabed infrastructure such as cables. Multiple dumps may be required to provide an initial layer of finer rock followed by a protective layer of larger grade rocks.

Dimensions Length 77.7m, Beam 19.1m, Deck Space 700 m2

Gross 2679te Tonnage

Propulsion 2 x 855 kW main engines and 2 x 600kW bow thrusters

Lifting 1,824te of bulk load (rock), plus 60te boom crane and 150te lifting frame capacity

Other DP capability Comments

5.12.30 In addition, small support vessels such as tugs or multicats may be used to assist with the deployment of barges or floating devices from port to the site, as shown in the table below.

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Table 5.20 - Indicative details of multicat vessel.

Variable

Vessel Type Small Support Vessel (Multicat / Tug)

Typical Whalsa Lass (Multicat) Example

Picture Image source: Delta Marine

Description Multiple use vessels with moderate lifting capacity and deck space, frequently used to transport small loads and tow floating devices. Anchor/mooring handling is another key role for these vessels.

Dimensions Length 26.0m, Beam 11.5m, Deck Space 160m2

Gross 225te Tonnage

Propulsion 3 x Caterpillar C32 TTA, with three props, giving a total power of 1,902kW

Lifting 2 x 10te cranes (@16.5m), Bollard pull 37.2te capacity

Other Some vessels have DP capability Comments

5.12.31 It is anticipated that up to 900 return journey vessel movements will be required per year during construction. As the construction will last for an 18 month period spread over up to three years (see Section 5.13 for further detail), it is estimated that there will be up to 1350 return journey vessel movements over that period.

Port and vessel requirements during construction

5.12.32 Each tenant will have different requirements during construction, resulting in the possible use of a wide range of vessels at PTEC. Construction equipment will largely be brought in via sea from the UK and mainland Europe. Vessels may be deployed from various UK and European ports, however it is envisaged the following local ports may be used, depending on the tasks being undertaken:

• Ventnor Haven;

• Cowes;

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• East Cowes; • Bembridge; • Yarmouth;

• Southampton; • Portsmouth; or • Marchwood.

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Figure 5.57 - Map of ports within 50km of PTEC

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5.12.33 Ports further afield may be used if tenants deem them to be more appropriate.

Navigational safety zones

5.12.34 During the construction phase temporary navigational safety zones are likely to be required for conducting activities which result in the vessels having limited manoeuvrability. These activities could include installation of cable, foundations, device support structure, TECs, and superstructure. This work will be of a limited extent and temporary nature.

5.12.35 The extent of the navigational safety zone will be developed in agreement with the MMO and the Maritime and Coastguard Agency (MCA), but may be around 500m. Chapter 19, Shipping and Navigation and Appendix 19A Navigation Risk Assessment provides more details on navigational safety zones and other mitigation requirements.

Discharges to air and water during construction

5.12.36 A small quantity (up to 5m3 per pile) of non-toxic cementitious grout may be discharged during the installation of piled foundations and the connection of some fixed device support structures to piles as discussed in Section 5.5. The grout discharged into the sea is expected to fall in the area surrounding the device, however it is likely to get dispersed and transported away from the device by tidal currents.

5.12.37 Construction vessels will result in discharges to the sea water and the atmosphere. These will conform to the relevant maritime standards and regulations and are therefore not discussed here.

Pile drilling operations and trenching works in the nearshore regions will unavoidably release sediment into the water column, however, this is anticipated to be relatively small volumes (see Table 5.8 and Table 5.9) which are likely to be quickly dispersed (see Chapter 7, Physical Processes for more detail).

Underwater noise generated during offshore construction

5.12.38 Underwater noise will be created by construction works including foundation drilling, vessel activity, and laying of cables and cable protection. Detailed modelling results are discussed in Appendix 5A Underwater Noise.

5.12.39 Predicted noise levels for the construction of device foundations by means of percussive drilling for the maximum pile size (4m) are shown in Table 5.21 and Figure 5.58. Chapter 13, Marine Mammals and Chapter 14, Fish and shellfish consider the impacts of underwater noise on relevant receptors.

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Table 5.21 - Summary of modelled ranges for unweighted levels in 10 dB increments for percussive drilling operations for installing a 4 m diameter pile.

South West Location

Maximum Range (m) Minimum Range (m) Mean Range (m) 160 dB re 1 µPa 18 17 18 150 dB re 1 µPa 69 68 69 140 dB re 1 µPa 280 270 280 130 dB re 1 µPa 1100 1100 1100 120 dB re 1 µPa 4300 3800 4000 110 dB re 1 µPa 13600 4100 10600

Figure 5.58 - Contour plot showing the predicted RMS level from percussive drilling operations at the south west location for installing a 4 m diameter pile.

5.12.40 Appendix 5A, Underwater Noise provides a summary of approximate underwater noise levels from other sources such as vessels, rock placement and trenching. (Table 5.22)

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Table 5.22 - Summary of the modelled ranges for noise levels in 10 dB increments from other noise sources that may be present during construction of tidal devices at the PTEC site

Range (m) Vessel Noise Vessel Noise Trenching Rock Placing (Medium) (Large) 160 dB re 1 µPa 8 9 1 4 150 dB re 1 µPa 49 67 7 32 140 dB re 1 µPa 280 440 50 200 130 dB re 1 µPa 1500 2500 300 1000 120 dB re 1 µPa 6300 9000 1300 3000 110 dB re 1 µPa 17000 20000 3600 6100

Offshore construction personnel requirements

5.12.41 Offshore there could be up to 80 staff on site at any one time, sufficient to simultaneously operate up to two large DP vessels during times of cable and / or device construction.

Onshore construction

5.12.42 Onshore construction will include the following principle activities:

• Cable landfall, either:

o Intertidal/foreshore trenching including possible temporary removal of coastal protection to allow cable installation followed by reinstatement of the coastal protection;

o HDD; or o Through the existing outfall pipe. • Possible installation of transition pits to joint marine and onshore cables;

• Onshore cable trenching from either: o The transition pit(s); o The landfall along or adjacent to the slipway (with no transition pit);

o The HDD location; or o The break out of the outfall pipe at an existing access point. • Installation of cables in trenches;

• Cable installation from landfall to the project substation/control room; • Enabling works including: o Possible alterations to the private access roads within the onshore site;

o Temporary closure and/or diversions to the public rights of way and coastal path through Flowers Brook/Castle Cove, with possible temporary enabling works to the public rights of way and slipway during this time;

o Creation of parking area; o Creation of temporary laydown/construction areas, including site fencing;

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o Temporary portacabin facilities within existing hard standing or the footprint of a feature described above, e.g. temporary laydown and construction area; o Construction of temporary security site fencing/provisions;

o Possible tree and scrub clearance; and o Foundation excavation. • Construction of the PTEC substation/control room building(s) including an outdoor fenced transformer compound; • Installation of transformers, switchgear and other electrical infrastructure within the substation/control room; and

• Termination of cables and wiring of electrical systems; and • Reinstatement of access roads/public rights of way/coastal path and affected ground.

Cable landfall

5.12.43 Cable landing onshore is achieved through the use of a shore mounted winch which pulls the cable ashore from the vessel. The cable pull-in is controlled from the cable lay vessel, and may be utilised to reduce the pull-in load and enable final positioning (see Figure 5.55 above). The cables will either be laid in a trench, or pulled through preinstalled ducts. This process will be undertaken 3 times to install the three bundles of two cables.

Trenching and rock armouring works

5.12.44 The preferred landfall method is an open cut trench, using an excavator to dig a trench for the cables in the intertidal region and shallow waters (less than 10m deep). The length of this trench is expected to be in the range of 200 to 500m, and be approximately 3m to 10m wide. In 5m to 10m water depth, the excavator will be operated from the deck of a barge as shown by the example in Figure 5.59.

5.12.45 An excavator, operating on land, will continue the trench to a point approximately 7m above Chart Datum. The excavator will clear an area of the coastal protection rock revetment for this trench.

5.12.46 This trenching work will either be undertaken in conjunction with the offshore cable installation works, involving the burial of the cables shortly after they have been pulled ashore; or it will involve the installation of ducts through which the cables can be pulled at a later date.

5.12.47 The coastal protection will be reinstated, including re-laying rock material, once the cables or ducts have been laid.

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Figure 5.59: Shallow water excavation from a jacked-up barge and excavator 5.12.48 Where possible, material that is excavated in the nearshore trenching works will be used as backfill into the trench after the cables have been laid. The trenching work in the subsea regions will unavoidably release sediment into the water column; however, this is anticipated to be a small amount over a relatively short period. Where excavated material cannot be used as backfill or landscaping, it will be removed from site either by barge or HGV.

Horizontal directional drilling

5.12.49 HDD may be adopted at landfall for short distances to shore if it is not possible to achieve a conventional landfall by trenching, or through the Southern Water Services Ltd emergency outfall pipe. There would be up to three HDD ducts, one for each export cable bundle.

5.12.50 HDD is a steerable trenchless method of installing services (such as pipes and cables) over a defined route underground with negligible disruption to the surface above the drill route. If adopted, HDD would be conducted from land, creating a conduit up to typically 1km that the cable is pulled through.

5.12.51 HDD consists of drilling a small diameter pilot hole under directional control along a predetermined path. A ‘pullback’ duct pipe is then connected to a reamer which is then pulled back through the pilot hole to provide an enlarged opening in which the cable or ducting can be installed. The process is illustrated in Figure 5.60, in this instance HDD is adopted to place a service pipe beneath a river.

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Figure 5.60 - The HDD process for a cable (red).

5.12.52 The onshore HDD area will be situated on level ground close to the location of the proposed PTEC substation/control room. The HDD process will require a temporary area of hard standing shown in Figure 5.49 and Figure 5.50 where a 120T drill rig would be situated to drill each up to 0.5m diameter bore.

5.12.53 A launch pit (typically 2m wide x 2m long x 1.2m deep) will be required inside the onshore drilling area. This pit will control the drilling fluids which will be pumped through a fluid recycling system into the drill head, enabling the drill fluid to be reused. In addition to the , a fluid recycler (typically 3m x 9m), pump and a tooling area will be located on site.

5.12.54 Once three holes have been drilled, cable ducts installed and leading line pulled through the duct, the cable lay vessel would pick up the leading line from the duct end on the seabed, connect it to a winch line which would in turn be connected to the end of a bundled pair of berth power cables. An onshore winch would then pull in the leading line, winch line and bundled pair.

5.12.55 The HDD process would generate approximately 35m3 of cuttings (300mm diameter over 500m) in addition to the injected drilling fluid required to lubricate the drill head. Drill cuttings would be removed from the site using HGV to an appropriate disposal site.

5.12.56 A short cable trench would be installed from the HDD pit to the project substation/control room.

Installation through the existing outfall pipe

5.12.57 If the Southern Water Services Ltd outfall pipe is used, each cable will be pulled through separately in its own duct using a similar methodology to pulling the cable through an HDD hole. A short cable trench would then be used to take the cable from the nearest existing manhole to the project substation/control room (Figure 5.51).

Transition pit installation

5.12.58 As previously discussed, a transition pit may be used to connect marine cables with onshore cables, giving greater flexibility in the onshore cabling.

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5.12.59 It is likely that two transition pits would be required, each being approximately 8m x 4m and 1m to 1.5m deep. After the completion of the works, the transition pits would be re-covered and the site returned to its original state, leaving very little evidence of their existence other than manhole access.

5.12.60 The subsea cables could either be connected to three-core, equivalent onshore cables or split out into three separate single core cables each carrying a single electrical phase. The preferred option here is likely to be the use of multiple, single core cables (i.e. 3 onshore power cables per subsea export cable). The transition pit would also allow the fibre optics and auxiliary power cables to be split out of each subsea cable. All of these cables would be incorporated into a trench about 1m deep and approximately 3m wide. The trench would be partially backfilled with sand and appropriately marked.

Onshore cable

5.12.61 If the cable landfall is at the slipway, the same open trench methodology as described in Paragraphs 5.12.44 and 5.12.45 will be adopted over a distance of approximately 250m between the slipway and the substation/control room. Two route options are shown in Figure 5.47 to Figure 5.48.

5.12.62 In the case of Option 1 (Figure 5.47) the public right of way which runs along the track through Flowers brook would be closed for up to 8 weeks.

5.12.63 Using the alternative options, the outfall pipe or HDD, a short length of open cut trench is required where the cable exits the outfall pipe or HDD pit to connect to the location of the substation/control room.

5.12.64 Open cut trenching will be achieved using an excavator or backhoe loader. On completion the surface will be reinstated to match the existing conditions.

Figure 5.61: A cross section of the onshore cable trench showing the various individual cables for each berth laid within it. Enabling works

5.12.65 The construction site will be securely fenced with provision for office and welfare facilities, parking and general storage within areas of existing hardstanding or the PTEC onshore

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footprints shown in Figure 5.47 to Figure 5.48. Site fencing will be in place for the duration of the construction period.

5.12.66 Permanent access tracks, vehicle parking areas and foundations will be constructed using a backhoe loader or light excavator and dumper. Topsoil will be stripped and set aside for reuse within landscaping (or removed from site) prior to import of material for the hardstanding and construction of the buildings.

5.12.67 Depending on the final substation/control room location and onshore cable route some tree and shrubbery clearance may be required. Levelling of the substation/control room site may also be required.

5.12.68 On completion of the construction works all construction compounds, temporary fencing, the temporary laydown and construction area, and facilities will be removed and these areas of land reinstated to pre-construction conditions.

Substation and control room construction

5.12.69 The substation and control room will be constructed using standard building practices associated with the portal frame structure or masonry methods proposed to minimise complexity, disturbance and environmental impact. Where required, concrete will be batched on the Isle of Wight for delivery to site.

5.12.70 A small mobile crane and cherry picker will be used on site to assist with construction of roof trusses or the steel portal frame structure and any further construction requirements (such as installation of electrical infrastructure).

Public access

5.12.71 To allow the works to proceed safely it may be necessary to temporarily close and/or divert the public rights of way and coastal path through the Castle Cove and Flowers Brook area for up to 8 weeks as cable installation works are undertaken. Temporary enabling works to the public rights of way, coastal path and slipway may also be required during this time. If temporary closures occur, PTEC Ltd will aim to complete this work in winter, avoiding seasons of peak activity in order to minimise disruption to the public.

Onshore discharges to water and air

5.12.72 In the event that HDD is adopted at the landfall, releases of mud and drill cuttings will occur as the drilled hole is cleared and filled with the cable duct. Approximately 350m3 to 400m3 of drilling fluids, typically a mixture of bentonite clay and water (considered non-toxic, earthen material), will be used in this process. All solids from the drill arisings are separated from the drill fluid and disposed of in accordance with the Site Waste Management Plan which will be developed during construction. This will likely stipulate the offsite removal of solids from the drill arisings.

5.12.73 As previously discussed, the trenching work in the subsea regions will release a small volume of sediment into the water column; however, this will be over a relatively short period. Where excavated material cannot be used as backfill, it will be removed from site either by barge or HGV.

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5.12.74 No further discharges to air or water are expected during onshore construction. A Site Waste Management Plan according to appropriate guidelines will be produced specifying how will be disposed of.

Noise generated during onshore construction

5.12.75 Onshore construction noise will principally result from construction activities associated with construction of the substation/control room building and associated infrastructure/works. The principle source of noise may be from construction plant, and specifically HDD activities associated with the installation of export cables if this installation method is used. Onshore noise is discussed further in Chapter 22, Onshore Noise.

Onshore traffic during construction

5.12.76 Vehicular access to the onshore site will be provided by the existing access tracks from the A3055 main road. Minor improvements to these private access tracks within the onshore site may be required with additional permanent hard standing for parking of up to 7 vehicles

5.12.77 Offsite vehicle trips of large vehicles will be predominately limited to the mobilisation and de- mobilisation of construction plant at the start and end of the constriction phase, plus the delivery of construction materials. The work will utilise car parking facilities at the compound. Table 5.23 provides an overview of the anticipated average vehicle trips per day and over the duration of construction for key aspects of the onshore construction work. The maximum number of HGV loads in a single day (24hours) is anticipated to be ten (20 trips).

Table 5.23 – Average onshore construction vehicles.

Task Average no. of vehicle trips per Vehicle trips over construction day period

Offshore HDD / trenching and 12 staff vehicles (LGV/car) per 480 trips (over 20 days) cable pull in day = 24 trips

Offshore HDD / trenching arisings Average of 3 HGV load per day = 120 HGV vehicle trips (over removal 6 trips. 10weeks)

Onshore substation/control room Average of <2 HGV trips per day 360 HGV vehicle trips (over 34 and onshore cable installation weeks) works (delivery of materials, levelling of site and removal of material/waste)

Staff vehicles Up to 10 staff LGV/cars per day = Approximately 4700 trips over 12 20 trips to 18 months.

5.12.78 Traffic management may be required at the site entrance to manage vehicles trips (see Chapter 18, Traffic and transport).

Onshore construction personnel requirements

5.12.79 During onshore construction up to 30 staff will be required at the substation/control room and

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landfall / cable route at any one time, including all crews, project managers and client representatives. It is the intention that onshore staff accommodation, where it is required, will be provided through a combination of hotels, B&Bs or rented accommodation available in the local area.

5.13 Construction Schedule

5.13.1 Table 5.24 provides an overview of the duration for key aspects of the offshore construction programme.

Offshore construction

Table 5.24 - Offshore construction duration.

Task Max duration

Trenching in the shallow subtidal/intertidal (if required) 28 days

PTEC Ltd installation of export cables 20 days

PTEC Ltd installation of navigation buoys 4 days

PTEC Ltd installation of monitoring equipment (ADCPs) 1 day

Tenant construction of foundations: 5 days per device

• Drilling; or 5 days per device

• Gravity base with possible ground preparation 1 day per anchor (4 days per device) • Gravity or drilled anchors.

Tenant installation of support / superstructures and TECs 1 day per device

Tenant installation of inter-array cables 2 days per cable

Tenant installation of hubs 6 days for foundation + structure installation

Tenant installation of monitoring equipment (ADCPs) 1 day

Deployment of inter-array cable protection 15 days

Deployment of export cable protection 25 days

5.13.2 Some elements may be completed concurrently, including suing two concurrent foundation construction vessels. The maximum duration of each offshore construction activity is as follows:

• 300 days for foundation ; • 45 days for export cable laying and associated cable protection;

• 141 days for inter-array cable laying, associated cable protection; • 18 days for electrical hubs (if required); • 60 days for installation of the support structure, TECs and any superstructure on to the device foundations; and • 6 days for navigation buoys and monitoring equipment (ADCP).

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5.13.3 It is anticipated that some elements will be completed concurrently and as a result the longest duration for completion of all offshore construction works is anticipated to be 18 months with a maximum construction window of 3 years. This is to accommodate potential gaps in between PTEC Ltd and tenant installation, and it is expected that the work will commence in 2016/17.

Onshore construction

5.13.4 Table 5.25 provides an overview of the duration for key aspects of the onshore construction programme.

Table 5.25 - Onshore construction duration.

Task Max duration

Enabling works 6 weeks

Creation of parking area 2 weeks

Construction of the PTEC substation/control room building(s) including an outdoor 34 weeks fenced transformer compound

Possible Installation of transition pits to joint marine and onshore cables 4 weeks

Reinstate access roads/public rights of way/coastal path and affected ground 4 weeks

Possible temporary removal of coastal protection to allow cable installation 2 weeks + 2 weeks to followed by reinstatement of the coastal protection reinstate

Possible HDD 10 weeks

Cable trenching from either:

• The transition pit(s); 8 weeks

• The landfall adjacent to the slipway (with no transition pit); 8 weeks

• The HDD location; or – 1 week

• The break out of the outfall pipe at an existing access point. 1 week

Installation of cables in trenches 2 weeks

Installation of transformers, switchgear and other electrical infrastructure within 17 weeks (of which the substation/control room approx. 11days of piling may be required)

Termination of cables and wiring of electrical systems 13 weeks

Commissioning of electrical systems 13 weeks

5.13.5 It is anticipated that some elements will be completed concurrently and as a result the longest duration for completion of all onshore construction works is anticipated to be 18 months, with a target of 12 months. As discussed in Section 5.12, onshore cable installation across the Castle Cove and Flowers Brook area will be scheduled for winter months where possible to minimise disturbance associated with potential path closures during this work. Works will aim to minimise the amount of time that public rights of way through the onshore site are closed. It is anticipated that the work will commence in 2016/17.

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5.14 Operation and Maintenance (O&M)

5.14.1 The project will have a life of 25 years, during which time the tidal devices will be generating renewable electricity from the tidal currents. The method of operation will be the responsibility of the tenant but it is anticipated that operational requirements of the tenant’s devices will initially be through the PTEC control room within the PTEC substation/control room. It is envisaged in the long term, once operational experience has been gained, the systems can be monitored and controlled remotely from the operators’ offices with intervention at the control room only required infrequently.

5.14.2 Control and operation of the devices will generally be via the fibre optic cable cores embedded in the PTEC export cables. However, each device incorporates a back-up system to enable shut down in the event of a failure of the fibre optic system. Each tenant is likely to have specific requirements for these back-up systems; however, most are understood to be based on wireless technology.

Discharges to air and water during operation

5.14.3 Heat is transferred to the sea water from the cooling systems of the tidal devices and the subsea hubs but this is expected to return quickly to baseline .

5.14.4 Any possible leakage of the lubricants discussed in Section 5.8 will be through a gradual abrasion of coatings and antifoulant resulting in the discharge of these materials at a slow rate into the sea water.

5.14.5 No gaseous or liquid discharges are anticipated from the devices to the atmosphere.

5.14.6 Maintenance vessels will result in discharges to the sea water and the atmosphere. These will conform to the relevant maritime standards and regulations and are therefore not discussed here.

Electromagnetic fields (EMF)

5.14.7 The estimated total length of inter-array and export cabling is up to 21km and 46km (respectively) of cable (surface laid). This is a very small amount of low voltage cabling compared with large offshore wind projects, for example and with the PTEC cable having steel armour protection, the EMF will be significantly reduced.

Noise emissions during operation

Offshore – underwater noise

5.14.8 Modelling of underwater noise levels has been carried out to estimate the noise level from different sized operational tidal devices at potential device locations to the north east and south west of the development site. A detailed underwater noise modelling report is provided in Section 3.4, Appendix 5A. Chapter 13, Marine Mammals and Chapter 14, Fish and shellfish consider the impacts of underwater noise on relevant receptors.

5.14.9 Table 5.26 shows the worst case scenario of operational tidal devices with rotor diameter of 24m. Figure 5.62 presents the contour plots for rotors of 24m.

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Table 5.26 - Summary of the modelled ranges for unweighted levels in 10 dB increments for an operational tidal device with rotor diameter of 24 m.

South West Location Maximum Range (m) Minimum Range (m) Mean Range (m) 160 dB re 1 µPa 6 5 6 150 dB re 1 µPa 49 48 49 140 dB re 1 µPa 450 440 440 130 dB re 1 µPa 3400 2900 3000 120 dB re 1 µPa 12800 4100 8900 110 dB re 1 µPa 22100 4100 15900

Figure 5.62: Contour plot showing the predicted noise level from one operational tidal device with rotor diameter of 24 m at the south west location (worst case scenario for noise propagation).

5.14.10 During maintenance activities, increased vessel traffic will create underwater noise as detailed previously in Paragraph 5.12.40 and Table 5.22.

Onshore - in air noise

5.14.11 Onshore operational in air noise may arise from the transformers, and cooling systems within the substation/control room building and occasional staff vehicle trips during site visits. Onshore noise is assessed in Chapter 22, Onshore Noise.

Device and inter-array cable maintenance

5.14.12 Device and inter-array cable maintenance will be the responsibility of each tenant, however in order to incorporate potential maintenance activities in the impact assessment, an estimate is provided based on information from other projects. Tenants are expected to visit each device

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up to 10 to 15 times annually for both planned and unplanned maintenance activities. Many tenants plan to undertake at least monthly routine inspection / maintenance using small vessels.

5.14.13 TEC maintenance procedures vary with device types with some tidal technologies having built in mechanisms to raise the TECs to the water surface minimising the requirement for large maintenance vessels (see Figure 5.63 to Figure 5.65).

Figure 5.63 - Tidal Stream Ltd technology with TECs raised (left) and TECs in the operational position (right) (Image source: www.tidalstream.co.uk).

Figure 5.64 - SeaGen technology with TECs raised (Image source: www.marineturbines.com).

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Figure 5.65 - BlueTEC technology with TECs raised (Image source: www.westislaytidal.com).

5.14.14 Key parameters in regard to maintenance include:

• Maintenance vessel requirements; • Frequency of access; and • In situ or port based maintenance activities.

5.14.15 Typical maintenance jobs may include: diagnostic tests, oil changes and lubrication, replacement of control cards and sensors, removal of biofouling, overhaul or replacement of systems (gearboxes, generators, switchgear etc.). Major operations such as retrieval and repair following structural failures would require similar vessels and procedures as construction works.

5.14.16 A worst case scenario of one five hour visit to each device on site per month has been considered. During maintenance activities a navigational safety zone will apply around the O&M vessels. Offshore maintenance activities will be made available through Notices to Mariners (see Chapter 19, Shipping and Navigation).

5.14.17 Table 5.27 provides an indication of maintenance requirements and access procedures for representative tidal technologies which have been used to estimate the maintenance requirements at PTEC. These have been used in defining the assumed worst case scenario for O&M, described below.

Table 5.27 - Likely maintenance requirements for representative devices.

Representative Operation and Maintenance Requirements Key points

Device

Tidal Buoyant nacelle (remotely) released to surface and Buoyant nacelle, Generation towed by a Multicat or workboat to maintenance port. All Limited work will be carried out onshore. Floats to surface and towed to port by Multicat. (Seabed mounted single rotor.)

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Representative Operation and Maintenance Requirements Key points

Device

Voith Hydro Device designed for minimal interventions and high Access for planned O&M reliability (all transformers, switchgear, converters etc. anticipated only once every (Fast seabed are onshore), no gearbox or lubrication systems. few years mounted single rotor) Nacelle lifted with bespoke lifting frame via guide chains Resilient design attached to the foundation. TEC disconnected from cable and taken to shore for work. Bespoke lifting frame used to raise device

MCT The crossbeam is raised to the surface to access each Cross beam raised above rotor/drivetrain. Minor maintenance can be carried out water for routine maintenance (Twin rotor from the structure itself using the on-board crane and a tower) small RIB to access the structure. Major maintenance Complex maintenance may require the removal of the drivetrain and rotor requires Multicat to take requiring a large Multicat vessel. drivetrain / rotor to port

Tidal Energy Each TEC nacelle can be independently lifted from / DP vessel used to lift nacelle / Limited lowered onto the frame using a DP vessel or crane rotors barge with moderate lifting capacity. Work on the TECs (3 rotor seabed will be carried out onshore. TEC lifting operations would Device taken to shore for all mounted typically take only a few hours each. work platform)

Clean Current All work will be carried out onshore at O&M port. Access DP vessel used to lift nacelle / or Open Hydro for O&M requires similar vessel to installation (DP rotors vessel), although bespoke vessels may be developed (Ducted axial for larger projects. Device taken to shore for all flow TEC) work

Kepler The rotor is raised to the surface for access. Minor Rotor raised to surface for maintenance can be carried out from the structure itself access (Transverse using on-board cranes and a small RIB to access the axis) structure. Major jobs require the removal of the rotors Minor maintenance via requiring a heavy lift (DP) vessel. A dry plant room onboard crane incorporates personnel access to enable inspection and repair / replacement of bearings, seals, generator Dry plant room provides (gearbox) and electrical plant. access to electrical equipment

Scotrenewables The device is designed so that it can be accessed at sea Most maintenance can be or Bluewater so that a large proportion of the maintenance can be carried out on site carried out without removing the turbine from its (Twin rotor moorings. Device can be towed to port floating) by Multicat The device can, however, be towed by a small vessel to a nearby port for any major maintenance works.

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Representative Operation and Maintenance Requirements Key points

Device

Tidal Stream The Triton platform is designed to be stable enough to Most maintenance can be Limited carry out all but the largest of maintenance operations at carried out on site sea. (Multiple rotor Device can be towed to port buoyant Access can be gained for some operations through by Multicat platform) surface piercing elements (transformers, control equipment etc.). Platform is raised (through variable buoyancy) for access to TECs. These can then be separately removed to shore for major work as necessary.

Vessels for O&M would mainly be a workboat or Multicat. For removal of TECs, a large Multicat or possibly offshore DP vessel may be required.

SME Basic procedures and inspections can be carried out Buoyant design offshore, once the platform is raised to the sea surface. (Twin rotor Floats to surface and towed to buoyant mid More involved maintenance will require the platform to port by Multicat water) be retrieved, towed to the O&M port and lifted/slipped out of the water for work to be carried out.

Small offshore vessels such as a Multicat capable of towing the device will be used.

Electrical Hubs Varies depending on supplier and nature of the hub. N/A Likely to require access several times a year. The hub and foundation would either be lifted in its entirety or a buoyant hub may be remotely released and accessed by a much smaller vessel on the surface. A wide variety of DP vessels, heavy lift vessel, Multicat, workboats and ROVs may be used.

Offshore export cable maintenance and inspection

5.14.18 Inspections of the export cable infrastructure will be performed annually for the first two to three years, reducing to every 2 years thereafter.

5.14.19 The surveys will be undertaken by an vessel (similar to that in Table 5.16) using an ROV to assess the cables for any signs of damage or movement. There is no planned maintenance of the export cable. In order to incorporate unplanned cable maintenance into the impact assessment, a conservative estimate of major works (cable repair) of up to five times during the project’s life (25 years) is considered. In the event of a failure, the cable will be fixed by cutting and lifting the damaged section of the cable / cable bundle and replacing the necessary section with spare cable spliced in by the cable laying process described in Section 5.12..

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Port and vessel requirements during O&M

5.14.20 Each device will have different requirements during O&M, resulting in the use of a wide range of vessels by the tenants at PTEC. Vessels that are designed for specialised purposes such as those required for the more complex works at PTEC are likely to be deployed from various UK and European ports.

5.14.21 It is anticipated that during the operation phase, the maximum number of vessel movements (return voyages) will be 900 per year, however it is expected that the number of movements may decrease over the life of the project.

5.14.22 The ports used for O&M will differ depending on tenant requirements, however it is envisage the following ports could be used dependant on the tasks being undertaken:

• Ventnor Haven, • Cowes;

• East Cowes, • Southampton, • Portsmouth,

• Marchwood • Yarmouth, or • Bembridge.

5.14.23 Ports further afield may be used if tenants deem them to be more appropriate. O&M vessels are assumed to be an even mixture of offshore DP vessels and smaller workboats/Multicats, with a few RIBs to allow maintenance personnel access to devices.

5.14.24 Tenants will require port space or quayside access (for floating systems) for maintenance work. Large jobs may be carried out at the installation port.

5.14.25 As with construction equipment, replacement parts for maintenance will largely be brought in via sea from the wider UK and mainland Europe. Smaller equipment will also arrive by road. An even mixture of offshore DP vessels and smaller workboats/Multicats, with a few RIBs are likely to be the chosen O&M vessels.

PTEC onshore O&M requirements

5.14.26 The PTEC system itself will be controlled and operated by a single control desk within the control room. This will be hard wired into the 33kV and 11kV switchboards in the switch rooms. A trained PTEC operator will operate the system from the control room only. Access to the main switch rooms will only be by accredited persons certified to operate high voltage equipment.

5.14.27 Maintenance of the main switchboards and transformer will be of a scheduled nature annually. The relays would also be checked for operational correctness on a regular basis (typically every 3 to 6 months).

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5.14.28 Building services, such as lighting, heating and sanitary services would be maintained on an ad hoc basis.

Personnel requirements during O&M

5.14.29 O&M personnel requirements will vary with the type of work being undertaken and the size of vessel required. As an example, as little as 4 people may be required to undertake works from a small vessel or approximately 40 persons for activities undertaken from a large DP vessel.

5.14.30 The personnel requirements will also vary depending on the phase of each deployment; at the start, each tenant (between 3 and 6 tenants) is estimated to have approximately 2 people at the control room continuously for the first 6 months. It is anticipated that beyond the first 6 months, a monthly inspection at the substation/control room will be undertaken by 2 people per tenant. This would be increased for any unplanned maintenance requirements.

5.14.31 Further to the tenant’s personnel, PTEC Ltd will undertake routine visits to the substation/control room with approximately two personnel visiting the onshore site twice per week for a few hours each visit. There are also likely to be biannual inspections which may require around 4 personnel for one to two weeks per inspection.

5.14.32 PTEC Ltd proposes to use local personnel where possible.

5.14.33 General operational staff numbers may include:

• Up to 10 PTEC Ltd FTE staff (including management, admin etc.); and • Based on consultation, approximately 10 FTE person O&M teams for each tenant, assuming the largest (10MW) berth (circa 30 FTE staff in total). Additional marine and vessel support may be required over and above this figure. • Accommodation will be provided by a combination of hotels, B&Bs or rented accommodation. Onshore vehicle trips

5.14.34 Although Ventnor is accessible by public transport, it is assumed that operation will require staff vehicles (LGVs/cars), in-keeping with the personnel requirements described above resulting in:

• Approximately 1 vehicle per tenant (3-6 tenants) per day for the first 6 months of each deployment;

• Approximately 1 vehicle per tenant (3-6 tenants) per month beyond the first 6 months for the duration of each deployment; • Approximately 1 vehicle, twice a week for PTEC Ltd inspections for the life of the project (25 years); and • Approximately 1 additional vehicle, twice a year for the life of the project (25 years).

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5.15 Repowering

5.15.1 As PTEC is a demonstration site, it is envisaged that the tidal devices/arrays (within the relevant berths) may be replaced several times within the 25 year project life. To enable this change over of devices/arrays to be included within the EIA, principles have been developed such that the number of repowering events within this period can be sufficiently defined to allow robust assessment within the EIA process and to provide clarity in the consenting requirements.

5.15.2 A repowering of a device/array is defined as the end of a berth/array demonstration cycle, at which time the device foundations, support/superstructures, TECs, electrical hubs, tenant monitoring equipment, and inter-array cabling will be removed, in line with procedures adopted during decommissioning (see Section 5.16). Once all developer owned assets have been removed, the berth would then be available for ‘repowering’ where new devices may be installed to utilise the berth for further demonstration.

5.15.3 Following the removal of the tenant infrastructure, construction of new devices will be undertaken in accordance with the construction procedures for device foundations, support/superstructures, TECs, electrical hubs, tenant monitoring equipment, and inter-array cabling outlined in Section 5.12.

5.15.4 The PTEC Ltd infrastructure, i.e. export cables, cable protection, navigational markers, monitoring equipment, and onshore infrastructure will remain in place for the life of the project.

5.15.5 The repowering process differs from operational and maintenance activities where, for example, the TEC may be removed for maintenance, whilst the other infrastructure (e.g. foundations) would remain in situ.

5.15.6 The project duration takes into account the time required for repowering works as well as construction and decommissioning, allowing up to 20 years of operation for each tenant. Therefore the overall life of the project will be 25 years. The duration for repowering the largest berth size (10MW) is estimated to be 251 days (8 months) based on the following durations for decommissioning and installation of tenant infrastructure:

• 50 days for removal of foundations; • 23.5 days for removal of inter-array cables, associated cable protection and hubs (if used); • 10 days for removal of the support structure, TECs and any superstructure; • 0.25 days for removal of tenant’s monitoring equipment (ADCP);

• 100 days for foundation installations; • 47 days for inter-array cable laying, associated cable protection and hubs (if required);

• 20 days for installation of the support structure, TECs and any superstructure on to the device foundations; and • 0.25 day for installation of tenant’s monitoring equipment (ADCP).

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5.15.7 The duration of an array demonstration may vary dependant on developer requirements, however in order to inform the EIA a maximum number of repowering events have been defined in Table 5.28. The developer consultation process identified that, given the significant investment associated with a large array (>3MW to 10MW) it is likely that this will be left in for as long as possible; it is therefore assumed that there may be only one repowering event (i.e. 2 deployments) over the 25 years project life. For smaller arrays of 3MW or less there may be three repowering events (i.e. 4 deployments) over the 25 year project life.

Table 5.28 - Array replacement frequency.

Maximum number of change overs throughout the life of the project (excl. initial installation & Berth size Device capacity using the berth site decommissioning)

3MW or less 100kW - 3MW 3

>3MW to 10MW 500kW-6MW 1

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5.16 Decommissioning

5.16.1 After the planned lifetime of operation of PTEC, tenants will remove the tidal devices and associated tenant infrastructure from each berth and PTEC Ltd will decommission the PTEC Ltd associated infrastructure.

5.16.2 A decommissioning plan is provided in Appendix 5B and will be further developed for approval by the regulatory authorities, prior to decommissioning, as required by section 105 of the Energy Act 2004. This section provides an overview of the likely options.

Cables

5.16.3 There are typically three options for the electrical cables at the end of the project’s life. Appendix 5B provides a review of the benefits and disadvantages of each option:

• Reuse • Preserved in-situ

• Removed Reuse

5.16.4 Ideally the cables would be left in place at the end of the PTEC project and their ownership passed to a future project developer that could re-power the cables under another project. This would be subject to the condition of the cables after the life of the project.

5.16.5 If the cables could not be reused, then they may be preserved in situ or removed, as detailed below.

Preserved in situ

5.16.6 The simplest decommissioning method would be to leave the cables in place, however, PTEC Ltd would continue to be liable for the cables and the safety of other maritime stakeholders.

5.16.7 If they were to be left in-situ, the export cables would be cut off at the point where the cables are first buried or covered by rock bags or mattresses. The cut sections would be removed with minimal disruption of the seabed. Contingency plans would be put in place to ensure appropriate actions are carried out if the cables were later to become a .

Removed

5.16.8 The sections of cable that have been surface laid will be simpler to recover than those that have been buried below seabed sediment. The cable protection elements will either need to be moved in order to free the cable or the cable will have to be cut either side of the protection. These operations can be carried out by an ROV and so there will be no risk to personnel but it may be a lengthy process. Once freed, cable can then be floated to the surface, raised by crane or reeled back onto a ship mounted cable drum; the reverse of the installation process.

5.16.9 The overburden of the buried cable sections will need to be displaced in order to allow the cable to be removed from the seabed. Again, the reverse of the installation operation can

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occur as a jetting ROV can be used to clear the seabed material and extract the cable as it travels along the cable route.

5.16.10 A combination of these techniques may be used depending on how much protection the offshore contractors install and how deeply the cable is buried in places. These factors will be confirmed by the pre-decommissioning surveys and allow the decommissioning methodology to be finalised.

Protection material

5.16.11 The recovery of protection material such as rocks is deemed impractical and may pose unacceptable risk to vessels and personnel in the recovery process.

5.16.12 The steel within concrete mattresses may have excessively corroded during its time on the seabed. The lifting aids and the structural integrity of these elements may have deteriorated to such an extent that lifting them by crane to the surface would either not be possible or risky to the vessel should the bag or mattress fail during the lift. Furthermore, the recycling or reuse of protection material and elements has very little financial value to offset its recovery.

5.16.13 For these reasons, protection material is usually left in-situ on the seabed. Material that has been in place for 25 years will also be heavily colonised and so its removal would destroy the habitat it had formed.

Tenant devices and electrical systems

5.16.14 Tenants will remove foundations, TECs, superstructure and support structures as well as any electrical hubs / cables and monitoring equipment by a process which is approximately a reverse of the installation process.

5.16.15 Gravity base foundations and gravity anchors will be left in situ on the seabed (if agreed) and piles cut off at or below seabed. All working practices will be governed by an environmental action plan and health and safety policy.

Navigation buoys

5.16.16 The navigation buoys and their moorings and anchors will be recovered and taken ashore for refurbishment or disposal. This process will be a reversal of the operations originally undertaken in the deployment of the navigation buoys. This will require an anchor handling vessel to recover the buoy, moorings and anchor to its deck and transport back to port.

Decommissioning schedule

5.16.17 The worst case scenario for the decommissioning duration is based on the removal of each aspect consecutively. The duration is estimated to be approximately 276 days (9 months) based on the following:

• 150 days for foundations; • 22.5 days for export cables and associated cable protection; • 70.5 days for inter-array cables, associated cable protection and hubs (if used);

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• 30 days for the support structure, TECs and any superstructure; and • 3 days for navigation buoys and monitoring equipment (ADCP).

Onshore substation/control room

5.16.18 The appropriateness of decommissioning the onshore substation/control room may depend on whether the building can be used for an alternative purpose and if it has a lesser environmental impact to leave it in-situ so long as it remains structurally sound. This will be reviewed at the time and if decommissioning is required this is likely to be a reverse of the construction process for the substation/control room.

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5.17 Rochdale Envelope Summary

5.17.1 This section summarises the Rochdale envelope and provides an overview of the worst case scenarios of all key components of the project description which are taken forward in the impact assessments.

Offshore infrastructure summary

Offshore infrastructure provided by PTEC Ltd: • Surface floating navigation buoys; • A subsea cable network, including; o Export cable(s) to shore (up to 23km of paired cables, 46km of cabling in total); o Cable protection measures (where necessary); and • Site monitoring equipment.

Offshore infrastructure provided by developers/tenants: • Tidal devices, incorporating:

o Foundation structures and associated support and access structures; o Tidal Energy Convertors (TECs); and o Seabed preparation measures for foundation construction (where necessary).

• Possible use of electrical hubs or connectors as a means to allow multiple tidal devices to export power through the berth’s export cable(s); • Site monitoring equipment; and

• Inter-array cables within each berth (up to 21km of cabling in total) to connect tidal devices to one another and/or an electrical hub.

Tidal Energy converters covered under the Rochdale Envelope: • Axial flow TEC o Open rotor

o Ducted • Transverse axis TEC

Foundation types covered under the Rochdale Envelope: • Seabed mounted o Gravity bases;

o Pin piles (including screw piles); or o Monopiles. • Floating with anchors

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• Surface piercing and fully submerged

5.17.2 Table 5.29 to Table 5.32 provide the parameters for the offshore elements of the PTEC project.

Table 5.29 - Project parameters

Value Parameter Minimum Maximum

Total project size - 30MW (5km2)

Total number of devices across the site - 60

Total number of surface piercing devices - 30

Size of individual devices 100kW 6MW

Number of berths 3 6

Berth Capacity 1MW 10MW

Number of devices in a single berth - 20

Length of tenant Lease - 20 years

Project life - 25 years

Number of ‘repowering’ events (tenant 3 times for <3MW berth infrastructure removed from the site and replaced - Once for 3MW to 10MW by a new tenant’s infrastructure) berths

Table 5.30 - Worst case number of devices for each device type

Device type Per Berth Entire Site

Floating devices (e.g. Bluewater) 10 x 1MW 2 berths or 20MW

Fixed bottom mounted surface piercing tower 7 x 1.42MW (max. 2 berths or 20MW (e.g. SeaGen) 10MW)

Surface piercing floating platform (e.g. TSL) 8 x 1.25MW 2 berths or 20MW

Transverse axis with fixed surface piercing 10 x 1MW 2 berths or 20MW support columns (e.g. Kepler) = 12 columns

Fixed bottom mounted single rotor submerged (e.g. Alstom TGL or Voith) 20 devices or 10MW 3 berths or 30MW (60 devices) (Each submerged device may have a small surface marker buoy)

Mid water column moored (e.g. SME) (Each submerged device may have a small 20 devices or 10MW 3 berths or 30MW (60 devices) surface marker buoy)

Fixed bottom mounted ducted rotor submerged 20 devices or 10MW 3 berths or 30MW (60 devices) (e.g. OpenHydro)

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Device type Per Berth Entire Site

7 x 1.42MW (max. Multiple rotor seabed mounted platform (e.g. TEL) 3 berths or 30MW 10MW)

Navigational markers 6 6

Surface piercing electrical hubs 0 3

Table 5.31 - Worst case foundation, mooring and footprint parameters Parameter Per Berth Entire Site Up to 80,000m2 for a Total seabed footprint of devices single berth (max 2 2 168,000m (including area impacted by moorings) berths of this footprint) Total tidal device area - 1.04 km2 Total array area - 2.62km2 (including spaces between devices) 75m2 Total seabed footprint of electrical hubs - (max. 3 hubs) Total footprint of navigational markers <10,350m2 10,350m2 Total footprint of monitoring equipment (ADCPs) - 42m2 5,980m2 Total footprint of export cables - (46km total) 1,500m2 Total footprint of export cable protection - (max.150 rock bags or mattresses) 2,520m2 Total footprint of inter-array cabling - (21km total) 1,000m2 Total footprint of inter-array cable protection - (max.100 rock bags or mattresses) Total footprint from construction vessels (anchor barges incl. footprint of anchors and chain - 160,000m2 catenary) Up to 80m (±40m) in direction of flow Up to 60m (±30m) Floating device movement - perpendicular to flow 60m radius about foundation (for surface piercing platform device [e.g. TSL]) Volume of drill arisings - 9,780m2

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Table 5.32 - Worst case TEC parameters

Open rotor axial flow Ducted rotor axial Transverse axis TECs TECs TECs

Max single TEC swept area 452m2 201m2 1,350m2

Max device swept area 1,884m2 201m2 1,350m2

Max array swept area 6,594m2 2,010m2 6,000m2

Max development site swept 12,000m2 2 2 area 19,782m 6,030m (limited to 20MW)

Max tip speed for rotor 41m/s 26m/s 18m/s diameters of up to 16m

Table 5.33 – Maximum weight of offshore infrastructure placed on the seabed

Infrastructure Weight (kg)

Tidal device foundations 30,000,000

Drill arisings 9,780,000

Navigational markers 200,000

Monitoring equipment 600

Hubs 599,400

Inter-array cables 650,000

Inter-array cable protection 800,000

Export cables within the development site 717,000

Export cables within the subsea cable corridor 783,000

Export cable protection within the development site 574,000

Export cable protection within the subsea cable corridor 626,000

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Landfall summary

5.17.3 The landfall area for the subsea export cables from the development site will be at Castle Cove and the onshore infrastructure location at Flowers Brook.

5.17.4 The key components of the project description in relation to landfall include:

• Landfall works by either: o Trenching;

o HDD; or o Routing through an existing outfall pipe

5.17.5 The preferred landfall method is an open cut trench, using an excavator to dig a trench for the cables in the intertidal region and shallower waters less than 5m to 10m deep. The length of this trench is expected to be in the range of 200m to 500m, and be approximately 3m to 10m wide.

Onshore infrastructure summary

5.17.6 The key components of the onshore project description for the following:

• Landfall works including possible transition pits; • Cable installation from landfall to the project substation/control room; • A dedicated project substation and control room, either two separate buildings or one combined building; • Parking area; • Possible alterations to the private access roads within the onshore site;

• Temporary closure and/or diversions to the public rights of way and coastal path through Flowers Brook/Castle Cove, with possible temporary enabling works to the public rights of way, coastal path and slipway during this time;

• Temporary laydown and construction area, including site fencing; • Temporary portacabin facilities within existing hard standing or the footprint of a feature described above, e.g. temporary laydown and construction area; and

• Enabling works, including security fencing/provisions and possible tree / scrub clearance.

5.17.7 In order to define the Rochdale Envelope for the EIA, the worst case parameters for the onshore features are presented in Table 5.34 and have been defined based on the options shown in Figure 5.47 to Figure 5.48.

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Table 5.34 – Worst case project parameters

Parameter Value

Cable installation from landfall to the project substation/control room

The cable corridor area for trenching (preferred 3091m² (based on the longest route, following the option) existing track through Flowers Brook)

Within the corridor there will be either one 3m wide Trench widths trench or two 1.5m

The length of the cable trench will be approximately Trench lengths 200m

Approximately 200m to 900m length of HDD

HDD parameters Up to 0.7m diameter

Up to 3 HDD ducts

Number of Transition pit(s) Up to two

Transition pit size 36m²

Substation and control room

375m² (as either 2 separate buildings or 1 combined Total area building)

Transformer height 6.8m

Parking area 62.5m²

Possible private road/track alterations to ensure 286m² access is maintained

Temporary laydown/construction area including 2522m², includes sufficient area for HDD site fencing:

Construction summary

Offshore

5.17.8 Offshore construction will include the following principle activities:

• Foundation construction:

o Drilling; o Gravity base placement with possible ground preparation; or o Anchors (drilled or gravity base).

• Support / superstructure and TEC installation • Installation of export cables • Installation of inter-array cables and hubs if required

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• Placement of cable protection (rock bags) • Navigation buoys • ADCP

5.17.9 During the construction phase temporary navigational safety zones are likely to be required for conducting activities which result in the vessels have limited manoeuvrability. These activities could include installation of cables, foundations, device support structure, TECs, and superstructure. This work will be of a limited extent and temporary nature. The extent of the navigational safety zones will be developed in agreement with the MMO and Maritime and Coastguard Agency (MCA) but is anticipated to be around 500m.

5.17.10 Offshore, on-board vessels there could be up to 80 staff on site at any one time sufficient to simultaneously operate up to two large DP vessels during times of cable and / or device installation.

Onshore

5.17.11 Onshore construction will include the following principle activities:

• Cable landfall, either:

o Intertidal/foreshore trenching including possible temporary removal of coastal protection to allow cable installation followed by reinstatement of the coastal protection;

o HDD; or o Through the existing outfall pipe. • Possible installation of transition pits to joint marine and onshore cables;

• Onshore cable trenching from either: o The transition pit(s); o The landfall along or adjacent to the slipway (with no transition pit);

o The HDD location; or o The break out of the outfall pipe at an existing access point. • Installation of cables in trenches;

• Cable installation from landfall to the project substation/control room; • Enabling works including: o Possible alterations to the private access roads within the onshore site;

o Temporary closure and/or diversions to the public rights of way and coastal path through Flowers Brook/Castle Cove, with possible temporary enabling works to the public rights of way, coastal path and slipway during this time;

o Creation of parking area; o Creation of temporary laydown/construction areas, including site fencing; o Temporary portacabin facilities within existing hard standing or the footprint of a feature described above, e.g. temporary laydown and construction area;

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o Construction of temporary security site fencing/provisions; o Possible tree and scrub clearance; and o Foundation excavation.

• Construction of the PTEC substation/control room building(s) including an outdoor fenced transformer compound; • Installation of transformers, switchgear and other electrical infrastructure within the substation/control room; and • Termination of cables and wiring of electrical systems; and • Reinstatement of access roads/public rights of way/coastal path and affected ground.

5.17.12 To allow the works to proceed safely it may be necessary to temporarily close and/or divert the public rights of way and coastal path through the Castle Cove and Flowers Brook area for up to 8 weeks as cable installation works are undertaken. Temporary enabling works to the public rights of way, coastal path and slipway may also be required during this time. If temporary closures occur, PTEC Ltd will aim to complete this work in winter, avoiding seasons of peak activity in order to minimise disruption to the public.

5.17.13 During onshore construction up to 30 staff will be required onsite (onshore) at any one time, including all crews, project managers and client representatives. It is the intention that onshore staff accommodation will be provided through a combination of hotels, B&Bs or rented accommodation available in the local area.

5.17.14 There will be a maximum of 20 HGV trips in a day, with a total of up to 480 HGV trips over the duration of construction.

Construction schedule

5.17.15 The worst case scenario for the construction duration is based on the following:

• 300 days for foundation constructions;

• 45 days for export cable laying and associated cable protection; • 141 days for inter-array cable laying, associated cable protection; • 18 days for electrical hubs (if required);

• 60 days for installation of the support structure, TECs and any superstructure on to the device foundations; and • 6 days for navigation buoys and monitoring equipment (ADCP).

• A total of 570 days

5.17.16 It is anticipated that some elements will be completed concurrently and as a result the longest duration for completion of all onshore construction works is anticipated to be 18 months with a maximum construction window of 3 years. This is to accommodate potential gaps in between PTEC Ltd and tenant installation, and it is expected that the work will commence in 2016/17.

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5.17.17 The maximum duration for completion of all onshore construction works is anticipated to be 18 months, with some works being completed concurrently. Cable installation will be scheduled for winter months where possible to minimise disturbance associated with potential path closures during this work.

O&M summary

5.17.18 As little as 4 people may be required to undertake works from a small vessel or approximately 40 persons for activities undertaken from a large DP vessel.

5.17.19 Each tenant (between 3 and 6 tenants) is estimated to have approximately 2 people at the control room continuously for the first 6 months. It is anticipated that beyond the first 6 months, a monthly inspection at the substation/control room will be undertaken by 2 people per tenant. This would be increased for any unplanned maintenance requirements.

5.17.20 Further to the tenant’s personnel, PTEC Ltd will undertake routine visits to the substation/control room with approximately two personnel visiting the onshore site twice per week for a few hours each visit. There are also likely to be biannual inspections which may require around 4 personnel for one to two weeks per inspection.

5.17.21 General operational staff numbers may include:

• Up to 10 PTEC Ltd FTE staff (including management, admin etc.); and • Based on consultation, approximately 10 FTE person O&M teams for each tenant, assuming the largest (10MW) berth (circa 30 FTE staff in total). Additional marine and vessel support may be required over and above this figure. 5.17.22 These works are expected to result in the following staff vehicles (LGVs/cars):

• Approximately 1 vehicle per tenant (3-6 tenants) per day for the first 6 months of each deployment; • Approximately 1 vehicle per tenant (3-6 tenants) per month beyond the first 6 months for the duration of each deployment; • Approximately 1 vehicle, twice a week for PTEC Ltd inspections for the life of the project (25 years);

• Approximately 1 additional vehicle, twice a year for the life of the project (25 years);

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Decommissioning summary

5.17.23 A detailed decommissioning plan will be submitted for approval by the regulatory authorities, prior to decommissioning, as required by section 105 of the Energy Act 2004. A summary of the options includes:

• Cables - reuse, preserve in situ, or remove • Protection material – leave in situ

• Tenant devices (excluding foundations) and electrical systems– remove • Tenant device foundations - leave in situ, remove, or cut to a safe level • Navigational buoys and monitoring equipment - remove

Summary of embedded mitigation

5.17.24 During the development of the engineering design a number of embedded mitigation measures have been included to reduce the potential impacts of the project. These include:

• Avoiding development in a number of designated sites, including: o Heritage Coast; o Sites of Special Scientific Interest (SSSI); and

o Area of Outstanding Natural Beauty (AONB). • The South Wight Maritime Special Area of Conservation (SAC) could not be avoided for routing of the subsea export cable. However, the routing will avoid key reef features to minimise impacts on the seabed ecology as well as reducing physical risks to the export cable, in particular: o Avoid or minimise crossing of: . slopes; . scarps; . ridges; . scour lines; or . other areas where there are rapid variations in bathymetry which could represent a reef feature.

o Using appropriate cable protection to avoid the cable moving around on the seabed.

• Avoiding the disused munitions disposal site to the east of PTEC;

• Avoidance of protected wrecks; • Limiting the number of surface piercing devices (30) compared with the maximum number of submerged devices (60). In addition, the maximum number of the highest device types is further limited to 27; • The substation/control room building will be designed to be in-keeping in size and finish to the existing Southern Water Services Ltd pumping station;

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• Substation/control room locations have been selected with the aim of being unobtrusive and minimising impacts where possible; • Where appropriate, screening (e.g. trees) will be used to reduce the visual impact of the substation/control room; • The substation/control room fence will be closed wooden boarded to minimise noise propagation and visual impacts; and

• Footpath closures will be limited to a maximum of 8 weeks during the winter period.

5.17.25 Further to the reduction in CO2 emissions associated with developing renewable energy, throughout the design of the project, PTEC Ltd has given consideration to the reduction of carbon emissions. In particular the following elements have been considered:

• Onshore Cabling o During the assessment of onshore route trajectory, a thorough investigation was conducted into the possibility of using an existing outflow pipe for cable landfall to avoid trenching or HDD and thus minimise emissions during these processes. This option whilst still under consideration is no longer preferred due to the de-rating of the cables in the pipe due to heat build-up and risks associated with installation in the pipe. • Offshore Cabling

o The offshore cable will be largely surface laid due to the hard seabed at the site; this reduces the amount of time a large cable installation vessel will be required on site. However, the cable will still require protection and stabilisation. The preferred method of cable stabilisation and protection is to use rock bags (filter units) filled with locally sourced rocks. o These units are far less energy intensive than the alternatives, being the use of concrete mattresses (with larger embodied carbon), rock placement (with quarried materials usually sourced from Northern Europe), or split pipe sleeves (using cast steel and lengthening installation time with the cable vessel). • Offshore Construction o For the installation phase of the subsea cables, the methodology has been developed to allow the use of non-DP vessels - which would save an estimated 6 to 22 tonnes of fuel (16 to 58 tonnes CO2) per day [20 to 30t fuel per day (55 to 80t CO2) for a large DP vessel compared to 2 tug boats at about 4 to 7 tonnes of fuel each per day (10 to 18 tonnes CO2)]. Although it should be noted that the project is not restricting the type of vessels to be used, so ultimately, DP vessels may present an overall more advantageous solution for the project. • Civil works o The substation/control room and onshore construction elements (including trenches, transition pits, hardstandings, and associated works and enabling works.) have been designed / specified to enable (smaller) local contractors to undertake the works; resulting in a minimisation of travel and associated carbon emissions, but would also benefit the local economy. Local contractors have already been consulted on these works.

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5.18 Conclusion

5.18.1 The project details described in this Chapter of the Environmental Statement have been considered by each technical specialist, focussing on the key parameters relevant to the receptor. Section 4, of Chapters 7 to 25, outlines the worst case scenario for the relevant receptor and this is used as the basis for assessing the impacts. By assessing a realistic worst case scenario it is deemed that this provides the maximum potential impact and therefore a conservative assessment on which to base a consenting decision. The various options described in this chapter are encompassed under the worst case scenario (known as the “Rochdale Envelope”).

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