This research addresses the challenges of installing floating wind turbines on semi-submersible platforms, with a focus on managing relative motions during offshore integration. Traditional methods, which rely on large onshore marshaling yards, are constrained by the limited space available at ports to meet the increasing demands of the offshore wind industry.

In response, the study proposes a shift to floating-to-floating installation, where turbine integration takes place on a moored floater directly at the wind farm. A major challenge in this approach is controlling the relative motions between the two floating bodies. To address this, a multibody model is developed in OrcaFlex, simulating the interaction between a heavy lift vessel and the VolturnUS-S platform. This model highlights the complexity of relative displacements, providing the foundation for introducing concepts aimed at minimizing these horizontal motions.

The chosen concept features a donut-shaped external platform equipped with winches for horizontal motion compensation. In the proposed 10-step installation process, the turbine tower is suspended from a crane while a gripper restricts pendulum motions, and an Active Heave Compensation system manages the relative heave motions. The external platform, suspended below the tower as it is attached to the gripper, is first lowered and secured onto the floater. Once in place, the tower is lowered, with the winches providing the necessary stiffness to control relative horizontal displacements during this phase.

The winch wires are modeled as springs with equal stiffness applied in both horizontal directions. Time-domain simulations in OrcaFlex, validated by an analytical model in MATLAB, reveal that a stiffness of 8887 kN/m is required to effectively limit horizontal displacements to 0.2 m for significant wave heights up to 2.5 m. This design choice ensures 92% workability for this installation step, considering a maximum crane angle of 2 deg and a maximum horizontal relative displacement of 0.2 m. Ensuring functionality under the simulated sea states reveals a design requirement of 1823 kN for the compensation system in the horizontal direction for Hs = 2.5 m and a Tp ranging from 6 to 11 s. While this force exceeds the capacity of a simple winch, it remains within a feasible range for a dedicated compensation system.

This thesis is a about a novel float-over concept for the installation of offshore substations in the Dutch North Sea. This new technology is a topside jacking system integrated into the H-851 float-over barge which should be able to jack the topside to a higher elevation before a float-over installation.

First, a high-level concept design of the novel float-over technology is presented. Thereafter, the stability for the jacking stage is investigated via hand calculations. Analytical models are developed to model the jacking system during select stages of the float-over and jacking of the topside. These models are used to verify the assumed design loads on the jacking system and other components required to install the offshore substation. As of now, the design loads are based on guideline for a different type of float over making the design loads a guestimate.

The float-over barge H-851 proved to be very stable without ballasting during the jacking of the topside. Initial ballast errors did not affect the barges stability significantly, the effect was only a 30% increase in heeling angle for the worst case. The effect for wind loading was more profound as the heeling angle increased with 100%. Due to the large initial stability of the barge, the heeling angle after jacking is still of no concern. For the investigated cases, however, care should be taken to ballasting the barge before jacking as initial errors become larger after jacking.

It was found that the driving systems for the jackings system can be designed in the global horizontal direction using less than 5% of the topside weight, given the sea states in this thesis. A lower stiffness jacking system resulted in lower horizontal loads on the driving system. The jacking system showed a difference in local horizontal loads over the jacks from stern to bow as great as 150%. This is due to the position of the topside with respect to the centre of the barge and in combination with the roll, pitch and heave behaviour of the barge and topside.

The mating analysis had multiple findings. It was found that the impact loads on the LMU’s were significantly lower by using the jacking system compared to the DSF for North Sea waves. However, the effect of the horizontal load (compression force) was less significant which resulted in lower or equal loads on the LMU’s. The horizontal loads at the interface between topside and barge were larger for a jacking system compared to a DSF.

Increasing the stiffness of the jacking system resulted in an increase of loads on the jacks and LMU’s. This was found due to the lower eigen period in the dominant motion for stiffer jacks. An interesting finding is a torsion moment with its centre at the interface between barge and topsides. This point was found to be dependent on the stiffness of the interface.

The increasing demand for renewable energy sources has brought about the need for innovative solutions to harness energy from the wind. One such solution is floating offshore wind turbines (FOWT), which offer several advantages over traditional onshore wind turbines and bottom-fixed offshore wind turbines. FOWTs present a challenge concerning overall cost, using fewer mooring lines than seen previously in the offshore industry. Statistically, these mooring line failures are expected to occur annually in large turbine fields and could result in untethered turbines causing extensive financial and reputational damage. It is, therefore, critical to understand whether a single mooring line failure could endanger the entire system, creating a risk that must be reduced to a level that is as low as reasonably practicable (ALARP). The Tetraspar demo FOWT off the coast of Norway is used as a model to investigate the influence of mooring line failure on the mooring system. This thesis investigates the potential risks associated with the three-leg mooring system of a FOWT following mooring line failure. The research employs a simulation-based methodology coupled with insights from previous studies and a fault tree analysis (FTA) to estimate the increase in failure probability of a complete mooring system in case of a single mooring line failure relative to an intact system. Specific assumptions underpin this investigation, including a six-month repair time bridging winter weather till the repair campaign and categorising two mooring line failures in a three-leg mooring system as a complete system failure. This thesis's research is divided into two categories: new failure modes specific to Tetraspar and altered failure modes, which are fatigue-related modes already included in the FTA, adopted from previous studies. Findings highlight the risk of Tetraspar capsizing after a mooring line failure and potential issues with slack line events and fibre sections of the mooring line touching the seafloor. Low-frequency second-order drift significantly increases fatigue in the mooring lines and fairleads, evidenced by an over 1200\% fatigue increase in some instances. A FTA consolidates these findings, showing a total failure probability increase in broken line state of between 32\% to 137\% based on the assumptions made. The study reveals a notable increase in fatigue following a mooring line failure. However, this state will persist for only six months within the turbine's 20-year lifespan, accounting for 1/40th of its design life. With the implementation of a robust safety factor, these fatigue issues can be effectively mitigated. It is advocated that 'design for failure' is incorporated into a three-leg mooring system design to ensure the risks associated with TetraSpar are ALARP. Five recommendations are suggested for the design phase to ensure the TetraSpar and FOWTs achieve ALARP risk levels considering potential mooring line failure, offering solutions that do not necessitate on-site visits, and ideally creating a system that can endure for six months without intervention, allowing for repairs during the summer campaign for more cost-effective and safer operations.

This paper investigates the technical, life cycle, and economic feasibility of a 30 MW upscaled downwind turbine, comparing it to a 15 MW X1 Wind PivotBuoy downwind turbine and a benchmark 15 MW IEA Umaine VolturnUS-S upwind turbine in the 450 MW Sud de la Bretagne I wind farm site. The study is significant due to the rising energy demand, the potential for decreasing the levelized cost of energy with increased turbine size, and the optimized use of space. The size limit of current upwind turbine designs could be addressed using a downwind turbine solution.

The research is conducted by modelling the global dynamic response of the structure using OpenFAST and computing the natural frequencies and stresses using a finite element model. A lifecycle analysis is performed to identify potential pitfalls and bottlenecks by analysing the individual lifecycle phases. The economic feasibility is assessed by simulating the annual energy production using TOPFARM and utilizing structural analysis and lifecycle assessment to quantify capital, operational, and abandonment expenditures. Based on the annual energy production and the performance indicators the levelized cost of energy is calculated.

The findings indicate that while the global stability is within boundaries, the stress in members is too high with a simple scale-up of the proposed design. Bottlenecks are found in lifting operations and supply chain readiness. The levelized cost of energy and capital expenditure increased due to substructure self-weight, rendering the proposed 30 MW scale-up currently unfeasible when compared to the other two wind farms.
These findings are important as they demonstrate that the 15 MW X1 Wind PivotBuoy is not scalable without design changes. The levelized cost of energy does not decrease with an increased floater solution. The 15 MW X1 Wind PivotBuoy downwind turbine seems more economically viable, making it a more interesting option for future development.