• Energy Research

This paper provides a comprehensive review of the current state of the art of the economics and socio-economics of ocean renewable energy (ORE); the many ways in which the viability and impacts of an ORE project are assessed, and an analysis of the current weaknesses, issues or inappropriateness of the metrics and methodologies used in their definition and presentation. The outcomes of this paper are anticipated to benefit the ORE and wider renewable sector as a whole. The review revealed that, for the most part, the current study of economics and socio-economics of ORE remain separate and discrete areas of research. The economic methods utilised appear to be comprehensive but are limited to project (or private investor) level. The methods identified for socioeconomic assessment fall between traditional, and now routine, environmental assessment approaches and more novel holistic approaches such as ecosystem services and life cycle assessment. The novel section of the paper explored the connectivity between the economics and socio-economics of ORE in relation to project developments and policy/planning. A visualisation method was created of concentric rings intersected by related axis of economic, socio-economic and environment, and enabled the examination of the benefits arising from the connectivity between the two spheres. The concept of sustainable development process and the integration of environmental assessment for ORE was also explored and how it responds to differing stakeholder aspirations and interpretations. The analysis revealed that there was a divergence between public and private economic and socioeconomic assessments for ORE: environmental assessment is primarily a public responsibility but with significant inputs from the private developer involved while economic assessments are conducted primarily by the developer and/or investor at their own behest. However, the two spheres of economic and socio-economic for ORE are highly connected and synergistic and must be examined in a holistic manner.

Abstract This paper evaluates the potential for co-location of offshore wind turbines at sites being developed for tidal stream arrays as a method for reducing the cost of electricity. It is shown that for a typical tidal site, MeyGen in the Pentland Firth, UK, increasing the wind turbine capacity reduces the cost of electricity compared to operating tidal stream arrays alone. This is due to increased energy yield combined with reduction of capital expenditure based on the use of common grid connection and shared support structures. Assessment is made using tidal, wave and wind resource data for a three year period. The overturning moment about the base of a monopile supporting a wind turbine with two tidal turbines is only 8% larger than for a wind turbine alone in a strong current typical of tidal farms. The increased cost of infrastructure is small relative to the increased energy yield and for all array configurations of practical interest, the levelised capital cost of energy is estimated to be 10–12% less from a co-located farm than from a tidal turbine farm alone.

AbstractTidal and wind energy projects almost exclusively adopt horizontal axis turbines (HATs) due to their maturity. In contrast, vertical axis turbines (VATs) have received limited consideration for large-scale deployment, partly because of their earlier technology readiness level. This paper analyses the power density of turbine arrays comprising aligned and staggered configurations with decreasing turbine spacing of HATs and VATs with height-to-diameter aspect ratios from one to four at three real tidal sites. The VAT rotor has vertical blades extending over a portion of the water depth on a circular frame. Equivalent diameter is defined as $$D_0$$ D 0 = $$\sqrt{A}$$ A based on the projected rotor area for both VATs and HATs. The three-dimensional velocity field is computed using analytical wake models that capture cumulative wake effects. At highly energetic sites, e.g. Ramsey Sound (UK), HATs are the most suitable technology attaining power densities beyond 100 W m$$^{-2}$$ - 2 , whilst VATs provide higher power densities than HATs at those sites with low-to-medium velocities, e.g. Ría de Vigo (Spain) and Kobe Strait (Japan). At the latter site, VATs provided up to 35% larger energy yield than HATs over a 14-day tidal cycle. Our results show that VATs with height-to-diameter aspect ratios larger than three notably reduce wake effects even when deployed with a normalised turbine spacing of two $$D_0$$ D 0 , reaching an average power density capacity of 40.7 W m$$^{-2}$$ - 2 compared to HATs that attain 49.3 W m$$^{-2}$$ - 2 . This study outlines the higher efficiency of tidal stream energy compared to other renewable energy resources, e.g. offshore wind farms, reaching power densities at least one order of magnitude larger, and that VATs counterbalance their smaller individual performance with improved array synergy as wake effects are limited.

Describing the evolution of a wind turbine's wake from a top-hat profile near the turbine to a Gaussian profile in the far wake is a central feature of many engineering wake models. Existing approaches, such as super-Gaussian wake models, rely on a set of tuning parameters that are typically obtained from fitting high-fidelity data. In the current study, we present a new engineering wake model that leverages the similarity between the shape of a turbine's wake normal to the streamwise direction and the diffusion of a passive scalar from a disk source. This new wake model provides an analytical expression for a streamwise scaling function that ensures the conservation of linear momentum in the wake region downstream of a turbine. The model also considers the different rates of wake expansion that are known to occur in the near- and far-wake regions. Validation is presented against high-fidelity numerical data and experimental measurements from the literature, confirming a consistent good agreement across a wide range of turbine operating conditions. A comparison is also drawn with several existing engineering wake models, indicating that the diffusion-based model consistently provides more accurate wake predictions. This new unified framework allows for extensions to more complex wake profiles by making adjustments to the diffusion equation. The derivation of the proposed model included the evaluation of analytical solutions to several mathematical integrals that can be useful for other physical applications.

AbstractFar wake velocities of a single horizontal axis three-bladed turbine in shallow flow have been measured previously in the laboratory and shown to have self-similar velocity deficit profiles. Wake velocities of arrays of turbines with one, two and three transverse rows have also been measured and simply superimposing the velocity deficits for a single turbine is shown to give accurate prediction of combined wake width and velocity deficit, accounting for variable downstream blockage through volume flux conservation. Array efficiency is defined as the ratio of total power generated to what would be generated by the same turbines in isolation. From prescribed initial turbine positions, generally determined intuitively or by practical considerations, adjusting the turbine positions to increase the power from each turbine, using the chain rule, shows that relatively small movements of 3–4 rotor diameters may increase array efficiency to over 90%.

Site development for tidal turbines relies upon a good understanding of the onset flow conditions, with disk averaged velocity typically used as a reference to define turbine power and mean loading. This work investigates the variation of onset flow conditions which occur for the same disk averaged velocity. Analysis builds upon data previously acquired during the measurement campaign conducted for the ReDAPT project using bed mounted ADCPs \cite{Sellar2018}. These measurements define the turbulence characteristics and vertical shear profiles over the rotor plane which are incorporated into an efficient blade element method for prediction of unsteady blade loads. This method allows efficient calculation of blade loading for multiple onset shear and turbulence profiles, each with the same disk average velocity, to determine the cyclic loading which contributes towards fatigue. Predictions of fatigue loads from measured profiles are compared with predictions from profiles predicted for the same location with a MIKE3 model \cite{Gunn2014}. Within the water depth two vertical positions are analysed, with vertical shear profiles from measurements and a multi-parameter model used to define the onset. For a near-bed location, use of the averaged predicted velocity profiles neglecting variation of turbulence intensity with flow-speed provides fatigue loads to within 1\% of predictions obtained using all measured profiles of velocity and corresponding turbulence intensity. For the near-surface location, the same approach under predicts fatigue loads by 16-19\%. This is partly due to the occurrence of a wider range of turbulence intensities. Since this is nearly constant with flow-speed a scaling factor is applied to load cycles from predicted profiles to estimate the aggregated fatigue load obtained using all measured conditions, providing confidence that accumulated fatigue loads can be predicted efficiently from velocity profiles obtained from shallow water models.

This work determines the variation in the fatigue loading on a tidal turbine at two depth positions and two different locations within a site. Site data were obtained at the European Marine Energy Centre, EMEC, test facility in Scotland, which has been compiled at the University of Edinburgh. The turbine modelled is the 18m Diameter DEEP-gen 1MW horizontal axis turbine. A blade element method is combined with a synthetic turbulence inflow to determine forces along the blade over a period of five tidal cycles. The focus is on establishing the difference between the loads at one tidal site, with an emphasis on the variety of turbulent conditions, with the onset flow fluctuations as great as 17% and the average integral lengthscales varying from 11 to 14 m at hub height. Fatigue loading is assessed using damage equivalent loads, with a 30% variation between turbine positions and 32% between turbine locations within a site, for one design case. When long term loading is assessed, a 41% difference is found for aggregated loads for a near surface turbine and a 28% difference for a near bed turbine.