The balance of plant includes all the components of the wind farm except the turbines, including transmission assets built as a direct result of the wind farm.
About £600 million for a 1GW wind farm.
See relevant sections below.
Much of the benefit of larger turbines is largely realised by the reduction in balance of plant costs. Larger turbines mean fewer structures and less cable.
Like-for-like balance of plant costs will increase as wind farms are built further from shore and in deeper water.
The cables deliver the power output from the wind turbines to the grid.
About £170 million for a 1GW wind farm.
Cable manufacturers include Hellenic Cables, LS Cable, Nexans, NKT, Prysmian and Telefonika Kabel/JDR Cables. There are other submarine cable manufacturers, predominantly located in China and Japan, but they have yet to be used for UK projects.
A standard subsea cable used in offshore wind is made up of a stranded, profiled conductor with a combination of sealing layers, XLPE (cross-linked polyethylene) insulation and armouring. The mechanical properties of the XLPE are superior to many other forms of insulation, offering greater tensile strength, elongation and impact resistances.
Cables are laid up with insulation and armour coating around the conductors. They must have high chemical and abrasion resistance as well as tensile strength to survive the laying process and withstand wave and tidal loading for exposed sections.
There are three main insulated power core design types:
Wet designs have the advantage of being lighter and more flexible. Much of the development of 66kV subsea cables has focused on developing wet designs at high voltages than had been previously possible. Currently cables with voltages above 66kV are only available as dry designs.
Subsea AC cables have threes cores (one for each phase). Onshore AC cables have single cores and are laid in groups of three. DC cables (land and subsea) have single cores (two, positive and negative, for each circuit).
The terms low voltage, medium voltage and high voltage are not formally defined by the industry. For offshore wind, high voltage typically refers to any cable rated higher than 66kV and low voltage anything below 11kV. High voltage cables are generally associated with transmission networks and export cables whereas medium voltage is associated with distribution networks and array cables. The wind turbines generate at low voltage with a transformer at the base of the tower stepping up voltage to medium voltage.
A single extrusion line can produce around 200km of core per year (this equates to around 40cm per minute).
To avoid unnecessary handling, cables that will be installed subsea are ideally loaded directly onto an installation vessel from the factory.
Cables have a specified minimum bend radius and failure to maintain this during transportation or installation greatly increases the risk of damaging the cable, potentially leading to cable faults.
The cable lengths are delivered on drums with sealed ends in order to prevent entry of moisture and other damage. There has been consolidation in the market with the acquisition by Prysmian of Draka and General Cable, by NKT of ABB and by Telefonika Kabel of JDR Cables.
The export cable connects the offshore and onshore substations.
About £130 million for a 1GW wind farm.
Export cable manufacturers include Hellenic Cables, LS Cable, Nexans, NKT and Prysmian. There are other submarine cable manufacturers, predominantly located in China and Japan, but they have yet to be used for UK projects.
An HVAC export cable is 3-core whereas a typical HVDC has a bipolar design with two single-core cables. For a given capacity, HVDC cables are lighter with implications for the ease and cost of installation with subsequent savings in cable costs. HVAC cables suffer important losses over longer distances due to reactive power flow.
HVDC is often used for long distance transmission because the full capacity of the cable system can be used for transferring active power (because there is no reactive power flow in DC systems). HVDC converter stations are expensive and the savings from the use of HVDC cable are not realised until the cable route between the substations is around 80-100km. Even beyond this distance, project-specific considerations can make final concept choice complex in deciding between HVAC and HVDC.
AC export cables are typically rated between 132kV and 245kV, allowing export of 350-400MW per 3-core cable. The voltage chosen balances the cost of the cable per km, the number of circuits for the grid connection and the number of substations needed. The trend towards wind farms further from shore has been associated with an increase in export cable voltage. The industry standard for projects is now 220kV for HVAC export cables.
Medium voltage AC cables may be used for export for small wind farms close to shore. Their use for commercial scale projects in the future is therefore unlikely but medium voltage export is attractive for demonstration projects, for example at the Blyth Offshore Demonstrator, the European Offshore Wind Deployment Centre (Aberdeen Offshore Wind Farm) and Hywind Scotland.
The first commercial scale HVDC projects are using 320kV export cables. A pair of single-core 320kV cables can export up to 1,200MW per pair. In time, this maximum power will increase.
A 220kV three-core copper AC export cable has mass of approximately 90kg/m.
A 320kV single-core DC copper export cable has mass of approximately 40kg/m.
The cable core transfers the power through the conductor.
Cable cores are typically manufactured by the cable manufacturer. Usually, the core is made on the same site to avoid transport costs and limitation on core length if it needs to be moved by road.
The core is typically made up of the conductor, a screen, the XLPE insulation and a protective sheath. The sheath has historically been lead but alternatives are being developed on environmental grounds.
The conductor may be stranded copper or aluminium. Both have low resistance, excellent conductivity, are ductile and relatively resistant to corrosion. Copper has higher conductivity, 60% greater than aluminium, but is more expensive and the price is more volatile. Aluminium is lighter and therefore easier to handle. Overhead power cables are typically aluminium for this reason.
The cable should at least have a conductor cross section adequate to meet the system requirements for power transmission capacity. Energy losses can be reduced by using larger conductor but at a greater capital cost.
Three-core subsea cables usually have steel wire armour. Single-core cables have non-magnetic armour.
Single-core cables can be laid separated or close. Close laying gives lower losses. Separation eliminates mutual heating but means higher losses in the armour.
A 66kV subsea cable core has a cross-sectional area of between 150mm2 (14mm diameter) and 800mm2 with 13mm of insulation.
A 220kV subsea cable core has a cross-sectional area of between 800mm2 (32mm diameter) and 1600mm2 with 23mm of insulation.
A 320kV DC cable core has a cross-sectional area of between 1,000mm2 (40mm diameter) and 2500mm2 with 25mm of insulation.
The conductor screen is a semiconducting tape that surrounds the conductor, maintains a uniform electric field and minimises electrostatic stresses on the cables.
For offshore wind, XLPE cables are typically preferred to paper-insulated cables. XLPE cables are typically cheaper and lighter but are not currently available at as high a voltage as paper-insulated cables, which means that international interconnectors often still use paper-insulated cables. This is expected to change with market demand and developments in cable design.
Surrounding the insulation is a further screen, similar to the conductor screen.
The cable outer surrounds the core are materials to protect the cable and house the fibreoptic cable.
Fibre optic manufacturers: Hexatronic, Huber+Suhner.
Fibre optic jointers and systems: Aceda, CCL UK.
For a three-core cable, the cores are surrounded by non-conductive filling and packing material made from polypropylene. Its purpose is to maintain the cable’s shape, structure and surrounding by binding tape.
The armouring includes the bedding, the armour and the serving application.
A layer of polypropylene string is applied over the assembly as bedding for the armour wires. The armouring is usually made up of helical metal wires, often steel, surrounding the cable. The choice of armouring is important as will impact the cable's protective, handling and electrical properties.
Bitumen may be applied over the armouring to protect against corrosion and provide additional adhesion. A layer of polypropylene string is applied over the armour as cable serving to provide resistance to abrasion and to reduce friction during laying.
A polypropylene serving is applied with a black and yellow pattern to make the cable easily visible during laying.
A fibre optic cable is integrated into the power cable for communications. The cable is multimodal, meaning that it can carry a wide range of data at different frequencies, typically for voice, turbine, switchgear and security information. The typically has 48 strands.
Cable accessories are used to provide electrical termination and mechanical support for cables both during and after installation.
Interface plugs: Nexans, Pfisterer, Ridderflex and TE Connectivity.
Hang-off clamps: BMP, Vos Prodect and WT Henley.
Cable connectors: see cable manufacturers (B.1.1 Export cable)
Pulling heads enable the safe installation of the cable to the platform. It typically connects directly onto the cable armouring to ensure that all mechanical forces associated with pulling the cable via the J-tube are borne by the armour rather than the core. They are usually made from machined steel and hot dipped galvanised and zinc plated.
Kellums Grips are often used for lighter weight or lower tension installations
The termination hang offs ensure that the cable is mechanically secured after installation to ensures the mechanical stresses expected to occur during service life are safely borne by the cable structure.
Offshore junction cabinets are used as a disconnecting point for internal tower cable to external subsea array cables by means of T-connectors and made from marine grade stainless steel.
Coupling connectors installed in piggy back assembly to a T-connector allow a second cable connection. These connectors are insulated using ethylene propylene diene monomer (EPDM).
J-tube seals are used to seal the interface between the inside of a J-Tube and the riser. Water containing a corrosion inhibitor is normally introduced into the J-tube void.
Cable protection systems (CPS) are often employed to ensure the cable is not subjected to excessive loadings through the cable route as the cable departs the foundation and continues onto the sea bed.
Cable connector, T-connector
Jointing the segments of cable and testing during manufacturing.
In house by cable manufacturers.
Independents: Maillefer, Power CSL and WT Henley.
There are two types of joints:
Field rigid joints have generally been bespoke products because of the substantial variations in cable design between wind farms. There is growing interest, particularly by OFTOs, in developing joints that are suitable for a range of designs.
Cables undergo a series of tests before dispatch, dependent on the cable type and voltage class, including:
Tests on complete cable lengths including factory installed joints (if any).
Electrical test and diagnostics devices
The array cable creates loops or individual strings connecting all wind turbines to the offshore substation.
About £35 million for a 1GW wind farm.
Array cable manufacturers include JDR Cable Systems, Hellenic Cable, NKT, Prysmian and Twentsche Kabelfabriek. There are other submarine cable manufacturers, predominantly located in China and Japan, but they have yet to be used for UK projects.
Each turbine has of the order of 1.5km of array cable on either side associated with it, depending on turbine size and spacing.
Array cables are now typically rated at 66kV. The first generation of offshore wind farms typically used 33kV but the high voltage has been a major focus of technical development because they enable more capacity to be connected on a single string, reducing the length of cable required and reducing the number of switchgear bays needed on the substation.
With the deployment of larger turbines above 6MW this has driven an increase in conductor sizing, in addition to the elevated voltage. Whereas for earlier 33 kV wind farms included 630mm2 copper as the largest array cable sizing, projects in construction and planning phase are moving to 66 kV 800mm2 or larger for both copper and aluminium.
Array cables are typically supplied with cable accessories, although the manufacture of accessories may be outsourced. Cable protection may also be included in the supply scope but it is more often part of the installer’s scope.
Cables may be supplied as pre-cut lengths or as a continuous length, depending on the project’s requirements.
Several cable manufacturers have cable installation equipment and vessels but turnkey cable packages have typically been led by marine contractors. This is mainly because different wind farms have contrasting technical requirements associated with the soil conditions or water depth and these are not necessarily a good fit with the manufacturer’s equipment.
Optical fibre cable
Mechanical and chemical protection
Cable protection provides protection to cables at vulnerable locations, from the wave and tidal action and when the cable enters the wind turbine or offshore substation aperture or J-tubes.
About £2 million for a 1GW wind farm.
Suppliers for cable protection include Blue Ocean, Balmoral, CRP Subsea, First Subsea, Subsea Protection Systems , Synthetex, Tekmar, Terram and Vos Prodect.
J-tube seals provide a seal at the ends of the J-tube to prevent seawater entering the J-tube. Passive seals consist of a series of disks that are pulled up into the J-tube. Active seals require inflation after they have been pulled through into the J-tube, requiring a remotely operated vehicle (ROV). Seals are not used in all cases, but a sealed J-tube may be filled with a corrosion inhibitor. A bend restrictor prevents damage caused by excessive bending.
Cable stiffeners or CPS are also used for protection. If made from steel, they effectively weigh down the exposed cable. The CPS is typically positioned at the exit of the J-tube to the sea bed, or is designed to protect the cable through ballast or scour protection, and also through to any planned cable burial position.
Cable mats are also used to protect exposed areas of cable, such as where cables cross and where they cannot be buried. Mats are typically made of concrete or polyurethane.
Some suppliers offer a J-tube-less solution for monopile foundations by providing a clamp that enables the cable to be routed through a hole in the monopile.
The foundation provides support for the wind turbine, transferring the loads from the turbine at the tower interface level (typically around 20m above water level) to the sea bed where the loads are reacted. The foundation also provides the conduit for the electrical cables, as well as access for personnel from vessels.
About £280 million for a 1GW wind farm of 10MW turbines using monopiles at 30m water depth.
About £350 million for a 1GW wind farm of 10MW turbines using jackets at 40m water depth.
Design: Ballast Nedam, COWI, LICengineering, OWEC Tower, Ramboll and SNC-Lavalin Atkins.
Monopiles: Ambau, Bladt Industries, EEW SPC, Haizea Wind Group, Navantia Windar, Sif and Steelwind Nordenham.
Transition pieces: Bladt Industries, EEW OSB, Smulders, ST3 Offshore and Wilton.
Jackets and other space frames: BiFab, Bladt Industries, Harland and Wolff, Lamprell, Navantia Windar, Smulders and ST3 Offshore.
Concrete: BAM Nuttall, Jan de Nul and Vici Ventus.
Foundation design is a complex engineering task. Design requirements include gravity load, thrust and associated overturning moment, natural frequency, fatigue strength, verticality (over time), personnel access, cable entry and support. Design needs to take account of both wind and wave loading and in some circumstances must consider other environmental conditions such as earthquakes, typhoons and sea ice.
Over 80% of offshore wind capacity installed to date has been supported by monopiles driven into the sea bed, with jacket (and other space frame) foundations representing approximately 15%. Gravity bases are the least common design and most examples were deployed at early offshore wind farms in water depths of less than 10m.
Monopiles require more steel than jackets but they are easier to manufacture and install in volume and they are well suited to the geology of the North and Baltic Seas. For larger monopiles, a key design driver is their stiffness, as the natural frequency of the complete wind turbine structure needs to be kept between blade passing frequencies over a range of wind speeds and above wave loading frequencies in order to minimise dynamic magnification and control fatigue loading.
For larger turbines and in deeper water, the cost of monopiles rises substantially. At around 35m water depth, jacket designs become cost competitive. For a 10MW turbine at 30m water depth, indicative mass for a monopile (including transition piece) is around 1,650 tonnes. For a 10MW turbine at 40m water depth, indicative mass of a jacket (including pin piles) is 1,450 tonnes. It is easier to design a stiffer jacket structure for turbines of 10MW and above in order to meet natural frequency requirements, giving such structures the edge over monopiles. Jackets can also be used in a wider range of ground conditions, where the ground is either too hard or too soft to suit monopiles.
In shallow waters and benign ground conditions, gravity bases have been used successfully. The Blyth Offshore Demonstrator Project used concrete gravity bases in waters of 36-42m, but at relatively high cost, with a mass of 15,000 tonnes for the concrete base, steel shaft and substrate ballast. Concrete material prices generally are less volatile than steel, meaning that when steel prices are high concrete is more attractive. In some regions, they can also offer higher levels of local content. Self-floating designs that can be towed out and sunk are being developed to reduce the installation costs associated with heavy lifts..
The use of suction buckets for attaching the foundation to the sea bed is being explored and has been commercially deployed in only a handful of offshore wind farms such as Borkum Riffgrund 2 (Germany) and European Offshore Wind Deployment Centre (UK). These can be used with either jacket structures, or with monopiles (a “mono-bucket”). The main advantage is avoiding the loads associated with driving the monopile or pin piles into the sea bed. This both reduces noise for sea creatures and allows foundations to be installed completely assembled with all secondary steelwork. A range of other noise mitigation technologies such as long-impulse piling are being developed.
Innovations in monopile design are anticipated to increase water depths they can be used in accessing more seabed. In water depths greater than about 60m, floating solutions are expected, with the potential for commercial deployment in the mid-2020s.
The primary function of a monopile is to support the static and dynamic loads of the wind turbine through anchoring it firmly to the sea bed using the embedded part of the monopile. Secondary functions include supporting the wave loads on the monopile itself and enabling cable entry.
About £150 million for the monopiles for a 1GW wind farm.
Manufacturers: Ambau, Bladt Industries, EEW SPC, Haizea Wind Group, Navantia Windar, Sif and Steelwind Nordenham.
Monopiles are the most commonly used foundation type to date and are considered to be a proven technology by the offshore wind industry in water depths up to approximately 40m.
Typically, for a 10MW turbine, the dimensions will be up to 10m diameter, 120m overall length and 2,000 tonnes. A number of suppliers have the capability to mass-produce this type of monopiles.
The monopile is a cylindrical steel tube that is usually driven into the sea bed. The embedded section of the monopile is of constant diameter to allow entry into the sea bed.
A monopile will normally have a transition piece between it and the bottom of the turbine tower, which supports secondary steel work such as a boat landing, cable J-tube and personnel access systems. Monopiles have typically been joined to their transition pieces using a long joint, either cylindrical, with shear keys, or conical, filled with grout. Jacking points allow adjustment to ensure that the transition piece is vertical before the grout is poured. A separate transition piece also avoids pile driving on the flange below the turbine tower, and allows secondary steelwork to avoid pile-driving loads. There is a trend towards bolted joints between the top of a monopile and the bottom of a transition piece where a grouted joint is swapped for a bolted joint, which is faster to install. In some cases, a transition piece is not used.
Monopiles have evolved to be relatively simple cylindrical structures and as such are now made in highly automated factories with little work on top of rolling and welding of parallel cans. Two thirds of the cost is steel. They do not generally have a surface finish to resist corrosion.
Monopiles need to withstand the impact of pile driving into the sea bed. The pile needs to be designed to account for these impact loads, which will use up a percentage of its fatigue life. As it is a simple cylindrical structure it is relatively easy to transport and move into its vertical orientation.
Although monopiles are considered an established technology, innovation continues:
To improve corrosion resistance by using new types of coating.
The primary function of a jacket is to support the static and dynamic loads of the wind turbine by anchoring it firmly to the sea bed using a set of pin piles. Secondary functions include supporting the wave loads on the jacket itself and enabling cable entry.
A jacket foundation does not have a separate transition piece. The upper part of the jacket performs many of the functions of the transition piece, which are described in B.2.3 Transition piece and its sub-sections.
About £310 million for the jackets for a 1GW wind farm at 40m water depth. This cost includes the pin piles and the upper part of the jacket, which performs many of the functions of the transition piece.
Jacket suppliers include BiFab, Harland and Wolff, Lamprell, Navantia Windar, Smulders and ST3 Offshore.
Jacket foundations make up approximately 15% of current installed capacity and are typically used at depths greater than 30m.
There are several different versions of jacket structures, including three legged, four legged, “twisted” and “true X-braced”. Three and four legged versions are currently the most widely used.
Typical overall jacket size for a 10MW turbine: 22m by 22m footprint, 60m height, with jacket mass of 1,100t and total pin pile mass of 350t.
The supply of 100 jackets, as would be required for a 1GW offshore wind farm with 10MW turbines, is likely to require multiple fabricators.
Jacket foundations are used for a number of reasons other than where the sea bed depth is too deep for monopiles to be economically viable:
A recent innovation has been to use suction buckets, also known as suction caissons, to secure the jacket to the sea bed (with one suction bucket supporting each jacket leg instead of piles), as used in the offshore oil and gas sector. During installation, the weight of the structure is combined with differential hydrostatic pressure created by pumping water out of the bucket, to draw the foundation down to penetrate the sea bed. Suction buckets have the advantage of little or no piling noise. They can only be installed in certain soil conditions, preferably sand or clay that is neither too dense or hard nor too loose or soft. Sites with shallow bedrock or the presence of boulders in clay soils are not suited to suction buckets. To maintain verticality, the caisson can be compartmentalised so that differences in pressure can be applied across the base of the structure. High-pressure jets positioned around the skirt can also help the levelling process. A challenge is the lack of evidence showing how a suction bucket structure will behave under long-term cyclic turbine aerodynamic and wave loading.
Manufacturing savings can be achieved because a jacket design uses less steel than an equivalent monopile to support a 10MW turbine. This improvement is partially offset by the increased complexity of the welded nodes, the joints between pin piles and jacket base and the transition at the top between the lattice structure and the tubular tower base.
Jackets may make up a higher percentage of future installed capacity if:
The combination of load sets at a particular site with 10MW+ turbines favours them as a design solution.
The transition piece provides the connection between the foundation and the tower, typically extending around 20m above mean sea level (MSL). It also supports secondary steelwork which provides functions such as allowing personnel access via a work platform, supporting cables and supporting the corrosion protection system.
About £100 million for the transition pieces for a 1GW wind farm using monopile foundations.
Where jacket foundations are used, the function of the transition piece is fulfilled by the upper part of the jacket structure. The cost is therefore included in the supply of the jacket.
Transition piece suppliers include Bladt Industries, EEW OSB, Smulders, ST3 Offshore and Wilton.
Often supplied through a joint venture with the monopile supplier.
All foundation types have an upper part which is described as a transition piece. Monopiles usually have a separate transition piece (bolted or grouted). For jackets or concrete gravity base foundations this will be an integral part of the structure.
Typically, the top of the transition piece needs to be approximately 20m above the highest astronomical tide (HAT) to keep the working platform above the worst expected combination of wave height, splash height and storm surge. It is finished at the top with a flange that will mate to the flange at the base of the turbine tower. For a 10MW turbine, a monopile transition piece will weigh approximately 500 tonnes and have an upper diameter of about 7m.
The transition piece for monopile foundations will have a joint at its base; either a grouted joint or a flange for a bolted joint. Grouted joints require a number of jacking fixtures to correct any variation in the verticality of the installed pile prior to grouting to ensure a level flange on which to install the turbine and may require other features such as grout lines and shear keys. Transition pieces with bolted joints require the monopile to be installed to within a small deviation from vertical.
The transition piece is also the part of the foundation to which most of the secondary steelwork is attached by welded or bolted joints. Secondary steelwork can include boat landings, external access ladders, the external work platform, internal work platforms, the cable entry and support system and the corrosion protection system.
Protective surface coating is mandatory in the atmospheric zone (that part which is exposed to air) and splash zone (that part which is exposed to both sea and air), which accounts for nearly all of the transition piece. They are normally painted a bright yellow colour for visibility.
Most projects have installed davit cranes on the transition piece to transfer equipment, small replacement parts and consumables from the support vessel.
The crew access system and work platform enable operations service personnel to gain safe access to the turbine platform and allows loading, unloading and storage of equipment.
The crew access system and work platform are usually supplied as part of the transition piece, see suppliers of B.2.3 Transition piece.
In practice, the steelwork for the crew access system and work platform may be subcontracted to a smaller steelwork supplier.
Adverse weather conditions can limit access to turbines and delay essential maintenance, leading to revenue loss. Currently, most crew transfer vessels (CTV) (such as a catamaran) are able to offload crews in wave heights of 2m. Some turbines have systems to enable helicopters to drop crew but if used routinely, this is an expensive solution with health and safety concerns.
The simplest and cheapest option for turbines located close to shore is to use a small CTV. In this case, the vessel will press up against the boat landing, which consists of a pair of strong parallel vertical beams (known as "bumper bars") mounted onto the transition piece. This allows the service personnel to step across to a ladder located between and slightly behind the boat landing, clip into the fall arrest system, and hence gain access to the main work platform and the turbine. Intermediate rest platforms may also be included between the boat landing and platform access. This method of access is limited to significant wave heights (Hs) of approximately 1.5-2.0m. There are a number of systems which extend the range of sea conditions under which it is safe for personnel to transfer across to the access ladder.
Service personnel may also arrive on a larger service operation vessel (SOV) equipped with a motion compensated gangway. In this case, they can step straight from the gangway onto the main work platform. Motion compensated gangways allow turbine access with Hs of up to approximately 3.0-4.0m.
The main work platform is typically located about 25m above MSL in order to be clear of splashes during storm surges, even at high tide. It is sized to allow the storage of small ISO containers, which are frequently used to transfer parts and equipment to offshore wind turbines. They could also be used to store a generator, which is commonly needed before the turbine is connected to the grid.
The main work platform is surrounded by guardrails and will have lights and textured non-slip decking to provide a safe working environment.
Internal platforms are used to support equipment housed in the transition piece and to provide personnel access for installation and maintenance purposes. They are also used to seal the upper reaches of the transition piece from the sea and any harmful gases from the corrosion protection system.
These are usually supplied by the supplier of B.2.3 Transition piece
In practice, the steelwork for the internal platforms may be subcontracted to a smaller steelwork supplier.
The upper platform provides access to the bolted connection between the transition piece and the tower base.
The lower platform allows a seal to be made between the lower internal part of the monopile and the upper internal part of the monopile. This is because hazardous gases can accumulate inside the lower part of the monopile from the corrosion protection system.
Further platforms may be included:
To support the turbine transformer, switchgear and a personnel refuge, although these can alternatively be located in the lower reaches of the turbine tower.
Lightweight structural steel frame and decking
Davit cranes are used to lift equipment from a workboat up to the main external work platform.
Suppliers of davit cranes include CraneSolutions, Demag Cranes, Granada Material Handling, Liftra, Palfinger Marine and Sparrows Group.
A davit crane is a crane, which can lift loads from a workboat and slew them around in order to lower them onto the main work platform. They have become almost universally adopted on offshore wind turbines to lift tools, auxiliary generators and smaller spare parts of up to approximately one tonne.
They are particularly useful when a small CTV is used to access the wind turbine, as these vessels do not have a crane capable of lifting onto the main external work deck.
Tools and parts can also be moved onto offshore turbines using a motion compensated gangway, vessel crane or helicopter.
The J-tube or I-tube routes the array cables from the outside to the inside of the foundation and provides protection to the cables from wave action.
For a monopile, a J-tube is a steel tube of diameter approximately 300mm attached to the transition piece extending from platform level to a few metres above the sea bed. It is called a J-tube because the lower end is curved like a letter J so that the cable bends smoothly towards the horizontal, where it will enter the sea bed. Both ends of the J-tube have a bell mouth shape to allow easy cable entry. The cable will enter the lower end close to the sea bed, pass up through the tube where it will be protected from the action of waves, and will commonly exit around the level of the top of the transition piece. There are a variety of ways for the array cables to pass from the outside to the inside of the wind turbine. Both ends of the J-tube are normally sealed after the cable has been pulled through – see B.1.3 Cable protection.
In deeper water, the top of the monopile finishes higher above the sea bed so an I-tube can be used. An I-tube has a vertical lower end, because it is many metres above the sea bed. A cable protection system will need to be used for the exposed cable between the buried section and where it enters the I-tube to stop it flexing in tidal currents.
Another alternative is to have a monopile entry point in the side of the monopile a couple of metres above the sea bed. This will be sealed after the cable has been pulled in.
These same options are used to route and protect cables for jacket foundations and for gravity base foundations.
Corrosion protection protects the foundation from corrosion to the extent that is required.
About £20 million for the foundation corrosion protection for a 1GW wind farm using monopiles.
About £30 million for the foundation corrosion protection for a 1GW wind farm using jackets.
Suppliers of corrosion protection coatings suitable for use on offshore foundations include Hempel, International Paint and Jotun.
Suppliers of cathodic protection systems include Cathelco, Imenco Corrosion Technology and Impalloy.
Corrosion protection is an integral part of the overall wind turbine design and is essential to achieving the intended lifetime. Several distinct zones need to be considered for corrosion protection, these are the atmospheric zone, the splash zone, the submerged zone and the buried zone (that part which is below the sea bed).
Methods for corrosion protection include cathodic protection and corrosion protective coatings. Other methods for corrosion control, such as corrosion allowance and use of corrosion resistant materials, are important considerations in the design of foundations but are not covered in this section. Corrosion protection must also account for fabrication, transport and installation to avoid damage even before the wind turbine is operational. The corrosion protection system mitigates general and localised wall loss and is a prerequisite for attaining the fatigue of the structure.
The external surfaces of the atmospheric and splash zones are normally coated with high performance marine coatings. Although the atmospheric zone coating can be accessible for repair, it is costly to repair any coating offshore, more so in the splash zone. For this reason, the coatings are combined with a design corrosion allowance to give maintenance-free service at least for the foreseen lifetime of the wind turbine.
Cathodic protection systems are typically used to provide corrosion protection to the part of the foundation in the submerged zone. The application of a negative current to the steel structure reduces the voltage on the structure to a level at which oxidation, and hence corrosion, is suppressed.
Galvanic anode cathodic protection systems (GACP) comprise a number of sacrificial anodes made of aluminium or zinc-based alloys that are fixed to the steel structure below the waterline. The more active alloy in the anodes is consumed in preference to the structural steel. This galvanic action provides a self-regulating current source that protects the structural steel and other metal components of the foundation. The zinc or aluminium bars can be designed to be replaced periodically to extend the useful lifetime of the corrosion protection.
A variation of cathodic protection is the impressed current cathodic protection system (ICCP). This uses an external power source and rectifier to supply a negative current to the structure and a corresponding positive current to non-consumed anodes mounted adjacent to the structure. An ICCP is substantially lighter than GACP and causes less drag in the water than the numerous sacrificial anodes required by a traditional cathodic protection system. A reliable power supply and associated instrumentation is required, and the design needs to be robust enough to withstand possible damage from sea conditions such as waves and currents as well as from maintenance and operational activities.
Unprotected structures, particularly embedded in the upper layers of the sea bed, may be subject to microbiological influenced corrosion related to naturally occurring bacteria. The resultant damage can reduce fatigue life of these areas.
Reactions between the foundation, the sea and the sea bed material, together with reactions from the cathodic protection system can generate noxious gases, which will accumulate inside a monopile. The lower deck of monopiles will be sealed for the safety of maintenance technicians working above, whilst gas detection and ventilation systems may be used to monitor and safely vent the concentrations of the noxious gases.
In closed internal compartments, such as in jacket tubes, which have been welded shut, corrosion may be mitigated by control of humidity or depletion of oxygen. The inside of a monopile is not considered to be a closed internal compartment.
Paints and thermal metal spray coatings
Zinc or aluminium based sacrificial anodes
Impressed current cathodic protection systems
Scour protection prevents scour of the sea bed caused by the speed-up of water moving around the foundation, which safeguards the performance and integrity of the foundation.
About £10 million for a 1GW wind farm.
Rock installation firms: Boskalis, Peter Madsen Rederi, DEME Group and Van Oord Offshore Wind.
Scour mat suppliers: Naue, Norfolk Marine and SSCS.
Scour is erosion caused by the presence of a structure changing flow patterns and increasing sediment transport locally around the structure. Scour is therefore an important factor for all foundation types. If sea bed material around the foundation is removed by the action of scour then:
The ground conditions have a consequential impact on the scour assessment and scour protection design. The particle size distribution and the strength are key considerations for both. Non-cohesive sediments (such as sand) do not resist scour whereas cohesive sediments (clay and silt) and bedrock are better able to resist it. Other key factors are waves, currents, water depth and the structure dimensions. All of these need to be considered when estimating scour depths.
In non-cohesive sediments scour depth increases with pile diameter, with design scour depth applied as 1.3 times the diameter of the pile. Scour will therefore be a bigger problem with larger turbines, which require larger diameter piles to transfer loading into the ground.
Depth of non-cohesive sediments is therefore very important in determining accurate scour depths as these inhibit scour.
Jacket structures are expected to be less susceptible to scour due to the smaller diameters of the pile footprint. However, total scour around the foundation also needs to consider the spacing of the vertical legs and lower horizontal members.
The rate of increase in scour depth slows with time until it reaches an equilibrium depth, typically within the first year.
Once an estimate of the scour depth has been calculated, a decision can be made to design the foundation to cope with the scour estimate including an allowance for the scour depth, or design and install scour protection (which will prevent the scour from occurring). The additional cost of initial scour protection and repairs over time should be balanced against the cost of designing to cope with the anticipated level of scour. This highlights the importance of estimating the scour depth as accurately as possible.
Routine monitoring is required in either scenario to monitor the scour depth development or the effectiveness of scour protection to avoid the risk of movement to the foundations structures.
Crushed rock is most commonly used for scour protection. However, in some cases, rocks can sink into the sediment, and secondary scour around the scour protection can also occur which needs to be considered in the design. Alternatives to rock are available, for example concrete mattresses and geotextile sand containers.
Options for installation of scour protection vary according to design and include pre-pile installation, post installation or a combination of the two.
Scour protection, as well as the turbine structures, become habitats for a number of marine species. However, this may not always be seen as a positive impact as the habitats created, and thus the species inhabiting the habituates, are different to the baseline environment.
In 2018, European scour researchers kicked off PROTEUS, a new EU Hydralab+ project, which aims to improve the design of scour protection around offshore wind turbine monopiles and future-proof them against the impacts of climate change.
Rock or geotextile sand containers
Offshore substations are used to reduce electrical losses before export of power to shore. This is done by increasing the voltage, and in some cases converting from alternating current (AC) to direct current (DC) The substation also contains equipment to manage the reactive power consumption of the electrical system including the capacitive effects of the export cables.
About £120 million for a 1GW wind farm, considering an HVAC system.
Electrical components: ABB, CG (Pauwels), GE, Schneider Group and Siemens Power Transmission and Distribution.
Structure: Babcock, Bladt Industries, Chantiers de l'Atlantique, Harland and Wolff, Heerema, Hollandia, Navantia, SLP Sembmarine and Smulders.
Systems integrators: Engie Fabricom, Iberdrola, Ørsted, Petrofac and Semco.
Structural designers: Arup, Atkins, ISC and Ramboll.
Substations are often delivered as one element of a contract to connect the wind farm generating assets to the onshore transmission grid.
An HVAC substation topside (everything above the substructure) weighs between 1,200 and 3,000 tonnes. A 1GW wind farm is likely to have two or three substations.
An HVDC substation topside weighs between 12,000 and 18,000 tonnes. A 1GW wind farm would only have one HVDC offshore substation but will often be connected to the turbines by several AC convertor stations which would transform the 66kV output from the turbines up to 132kV or higher to feed the HVDC substation.
Developers typically work closely with their chosen supplier after the turbine has been chosen to optimise the transmission system as a key opportunity to reduce the cost of energy. By reducing the number of circuits, the substations need less switchgear and fewer transformers. This provides an opportunity to dispense with a substation or to reduce platform and foundation costs.
Standardisation of substation design offers the potential to lower costs, although few developers have the project pipelines to justify the upfront costs.
With the introduction of 66kV subsea cables, near shore wind farms up to 300MW can be built without an offshore substation
A typical HVAC platform is about 25m above the sea and has an area of 800m². Typically, a single substation can support the input of about 500MW. In some circumstances, the greater cost of higher capacity cables can be offset by savings on substation hardware.
Although many substations are not being used primarily as service platforms, they will still have a modestly equipped workshop and frequently a helideck.
The offshore substation is ultimately owned and operated by a transmission operator (OFTO in the UK); although the wind farm owner has access and responsibility for the array cable entry and wind farm switchgear.
The electrical system integrates AC power output from individual turbines and transforms voltage from for example 66kV to 275kV for export to onshore substation, else converts to DC for onward transmission.
About £45 million for a 1GW wind farm.
ABB, GE Grid Solutions and Siemens Power Transmission and Distribution.
Wind farm substation transformers: above plus Tironi.
Key components include:
Offshore substations located more than 80-100km from the onshore substation may use HVDC to reduce transmission losses. Concerns about the reliability of offshore HVDC convertor stations, and the higher capital costs have led some developers to implement technology solutions to allow AC transmission to be used over longer distances, such as lower frequency AC transmission. Some sites have used additional reactive power compensation equipment, located on offshore platforms part way along the offshore cable route, or in onshore substations close to the coast.
An HVAC system converts and transmits the electrical power generated by the wind turbines, at say 66kV AC, to the onshore substation through the export cables at say 275kV AC. Transformers in the onshore substation may increase the voltage further to say 400kV for connection to the onshore transmission grid.
ABB, Schneider Group and Siemens.
Transformers: above plus Tironi.
An HVAC transmission system, including the export cables and offshore and onshore substation, typically offers a lower lifetime cost (when also taking into account electrical losses) than the equivalent HVDC system for wind farms where the distance to the onshore substation is less than about 80-100km. The factors used in making the choice between HVAC and HVDC, however, are complex.
HVAC electrical systems use standard technology and systems, which may be customised for use in a marine environment.
Passive and active reactive power compensation
Auxiliary electrical, control and monitoring systems
Industrial waterproof enclosures
Cable trays, tracks, clamps and supports to protect electrical items
An HVDC system converts and transmits the electrical power generated by the wind turbines, at 66kV AC, and transformed to say 132kV AC by AC convertor stations, to the onshore substation through the export cables at say 375 kV DC. Equipment in the onshore substation converts the voltage back to 275kV or 400kV AC for connection to the onshore transmission grid.
ABB, Alstom, Hitachi, Mitsubishi Electric Corporation, GE Grid Solutionsand Siemens Power Transmission and Distribution.
An HVDC transmission system, including the export cables and offshore and onshore substations, typically offers a lower lifetime cost (when also taking into account the lower electrical losses of a HVDC system over these distances) than the equivalent HVAC system for wind farms where the distance to the onshore substation is greater than about 80-100km. The factors used in making the choice between HVAC and HVDC, however, are complex.
HVDC systems use relatively new technology and systems which are custom designed for the transmission of high power, say over 750MW, over long distances.
HVDC systems currently only operate point-to-point and require the use of a matched pair of converters at each substation (one onshore and one offshore).
HV AC and DC switchgear
Passive and active reactive power compensation
Auxiliary electrical, control and monitoring systems
Industrial waterproof enclosures
Cable trays, tracks, clamps and supports to protect electrical items
Auxiliary systems that support the operation and maintenance of the substation and enable some wider wind farm maintenance activities.
About £20 million for a 1GW wind farm.
Building monitoring systems (fire and gas detection, CCTV, access, security) suppliers include
Supply of general facilities is often local to assembly of the substation.
Like any other complex industrial facility, this offshore building needs fire detection and suppression systems along with security, safety, communications and other monitoring systems.
Fire and blast protection is required because the transformers contain oil and coolants and present a fire risk. They need to be protected from fires elsewhere on the platform.
Siemens Offshore Transformer Module HVAC substation uses Ester as the transformer cooling system. This is a non-combustible, biodegradable fluid that has eliminated the need for active fire suppression.
A standby generator is required to provide auxiliary power and lighting in the event of loss of connection to the onshore substation, and to provide power to restart and reconnect to the onshore substation.
An on-board crane to lift from a service vessel typically has a load capacity of around three tonnes.
Also required are a control room, health and welfare and refuge for visiting crews, clean and black water systems, fuel tanks, low-voltage power supplies, navigational aids and safety systems.
Auxiliary electrical systems
Fire and blast protection systems
Standby generator (normally for HVDC substations)
Control room & refuge
Clean and black water systems (normally for HVDC substations)
Fuel tanks (normally for HVDC substations)
Heating, ventilation and air conditioning equipment
The structure provides support and protection for the electrical and other systems.
About £60 million for a 1GW wind farm.
Structure: BiFab, Bladt Industries, Harland and Wolff and Heerema.
Helideck: Aluminium Offshore, Bayards and other suppliers to the oil and gas industry.
The steel structure is complex, with many safety considerations and services incorporated.
For a small substation, the foundation may be similar to a B.2 Turbine foundation, but with a different loading pattern. For a large substation, distributed piles or a jacket is preferable.
A helideck is generally specified to enable helicopter landing. Offshore helidecks are generally aluminium to minimise corrosion and weight. An accident during take-off or landing can result in hundreds of litres of jet-fuel spilling from ruptured fuel tanks so stringent safety regulations are in place with the requirement for an integrated fire-fighting system. The use of helicopters for crew transfer is an integral part of maintenance and service operations for some, but may only be used for emergency access or egress by others.
Access by vessel is similar to that for a turbine.
Helideck and/or heliwinch
The onshore substation transforms power to grid voltage, for example 400kV. Where a high voltage DC export cable is used, the substation will convert the power three phase AC.
About £30 million for a 1GW wind farm. This includes the buildings, access and security as well as electrical systems.
They are generally contracted to the same main contractor as the B.3 Offshore substation
Many of the electrical components will be similar in specification to the offshore substation, but constraints on weight and space are not as critical.
The substation will contain metering equipment to measure electricity exported to the grid.
The onshore substation is ideally located close to the offshore export cable landfall to limit the length of the onshore cable route, but it may be up to 60km from landfall.
The onshore substation is often the first part of the wind farm to be built, about a year before offshore construction. In some cases, work may start ahead of final investment decision for the wind farm to mitigate the risk of stranded generation assets.
Typically, they are two parts to the substation: the wind farm side owned by the offshore transmission owner (OFTO, in the UK) and the grid side owned by relevant grid operator (National Grid Electricity Transmission in England and Wales, SSE Networks or SP Energy Networks in Scotland, or Northern Ireland Electricity Networks).
The wind farm part of the substation is much the larger, consisting of high voltage switchgear, transformers (to step up from the export cable voltage to grid transmission voltage (400kV), reactive power management systems and a building with a control room, office and storage.
The grid-side substation may be an extension to an existing facility or a new one if this is not practical.
The onshore substation is likely to be contracted to a supplier of transmission systems with a substantial amount of the work contracted to a civil engineering contractor.
Buildings, access and security provide physical protection and security for the onshore electrical equipment that connects the wind farm to the onshore transmission network
About £8 million for a 1GW substation.
Buildings: any provider with a suitable track record of constructing architect-designed industrial buildings can respond to a tender to construct the building and compounds.
Access and security: industrial fencing, security including CCTV, access control systems, industrial LV systems, HVAC (short for heating, ventilation and air-conditioning) will be put out to tender and can be supplied by any pre-qualified supplier.
The buildings and associated compounds will be custom designed to suit the specific technical and planning requirements of the project.
For an HVAC substation, indoor space is required for housing some of the switchgear, monitoring systems and associated low voltage systems and welfare facilities for visiting technicians. Often about the same area of outdoor space is required for compounds for outdoor HV switchgear, termination of HV overhead lines, storage and car parking.
For an HVDC substation, indoor space, typically at least two storeys high, houses the HVDC converter, monitoring systems and associated low voltage systems and welfare facilities for visiting technicians. Outdoor space is also needed for compounds for outdoor HV switchgear, termination of HV overhead lines, storage and car parking.
Auxiliary and low voltage system
The operations base supports the operation, maintenance and service of the wind farm.
About £3 million for a 1GW offshore wind farm.
The wind farm owner is likely to choose a local construction company for the construction of the operations base.
Examples are Hobson and Porter, R G Carter Construction.
The specification for an operations base depends on whether the owner has chosen a shore-based maintenance and service strategy (using crew transfer vessels) or an offshore maintenance and service strategy (using service operation vessels).
For a shore-based strategy, the operations base consists of offices, warehousing, workshops, car parking and vessel berths. The total area of the site is likely to be about 8,000m2.
A 1GW wind farm with a shore-base strategy is likely to require up to 10 CTV berths. Fewer than this will be needed on a day-to-day basis but the owner will want to ensure that there is capacity to support peak turbine maintenance and service activity and for the use of balance of plant maintenance contractors.
CTVs use purpose-built concrete pontoons with mooring, electrical and water systems and a fast fuelling system. One CTV needs a berth of about 30m. The berths are likely to be built ready for the construction phase before being reutilised for operation.
For an offshore maintenance and service strategy, a base may be used to support several wind farms. Although, an SOV will only visit port every 14 or 28 days, the owner is likely to want a dedicated berth of about 100m. In theory, the administration of the wind farm does not need to be within the port but it is likely that owners will choose to locate it close to offshore operations.