At nearly 3,000 tonnes, the company said its lift of an FPSO module was one of the heaviest land-based crane lifts ever performed. ALE was contracted to lift six modules for Total’s FPSO module integration project in Nigeria. The subsea tieback is expected to start up in 2021. This is Shell’s second major development on a tieback in the US Gulf of Mexico, following Kaikias’ startup in May. Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned.
The majority of offshore fields have been developed with conventional fixed steel platforms. One common feature of fixed steel structures is that it is essentially "fixed" (i.e., it acts as a cantilever fixed at the seabed). This forces the natural period to be less than that of the damaging significant wave energy, which lies in the 8- to 20-second band. As the water depth increases, these structures begin to become more flexible, and the natural period increases and approaches that of the waves. The consequence of this is the structure becomes dynamically responsive, and fatigue becomes a paramount consideration.
Wellhead systems serve as the termination point of casing and tubing strings. As such, these systems control pressure and provide access to the main bore of the casing or tubing or to the annulus. This pressure-controlled access allows drilling and completion activities to take place safely with minimal environmental risk. Multiple barriers are used, such as primary and secondary seals, to reduce risk in case of equipment failure. Offshore wellhead systems are normally more sophisticated in design to handle ocean currents, bending loads, and other loads induced by the environment during the life of the well.
Jiang, Zhiyu (Norwegian University of Science and Technology, Centre for Research-based Innovation of Marine Operations) | Ren, Zhengru (Norwegian University of Science and Technology, Centre for Research-based Innovation of Marine Operations, Centre for Autonomous Marine Operations and Systems) | Gao, Zhen (Norwegian University of Science and Technology, Centre for Research-based Innovation of Marine Operations, Centre for Autonomous Marine Operations and Systems) | Sandvik, Peter Christian (Centre for Research-based Innovation of Marine Operations, PC Sandvik Marine) | Halse, Karl Henning (Centre for Research-based Innovation of Marine Operations) | Skjetne, Roger (Norwegian University of Science and Technology, Centre for Research-based Innovation of Marine Operations, Centre for Autonomous Marine Operations and Systems)
The assembly and installation costs of an offshore wind farm can approach 20% of the capital expenditures; therefore, time efficient installation methods are needed for installing offshore wind turbines. This study investigates the feasibility of a novel wind turbine installation concept using a catamaran. The catamaran is designed to carry wind turbine assemblies on board and to perform installation using lifting grippers. The installation of a rotor-tower-assembly onto a spar foundation is considered with a focus on the mating process of a tower-nacelle-rotor assembly. The spar foundation has been pre-installed at a representative site in the North Sea, and the catamaran has thrusters regulated by a dynamic positioning system. Numerical modelling of various components of the concept are introduced. Time-domain simulations of the system are performed in irregular waves, and the relative motion and velocity between the tower bottom and the spar top are analysed during the mating process. It was found that the active heave compensator can effectively reduce the relative heave velocity and the risks of structural damage during the mating process.
The offshore wind industry has witnessed continuous growth in the past decade. To improve the cost effectiveness of offshore wind power, there is a trend to design larger wind turbines for greater water depths. Various types of supporting structures have been proposed for offshore wind turbines (OWTs). Generally, for water depth less than 40 meters, monopile, gravity-based, and jacket foundations are the most commercially competitive (Pieda and Tardieu, 2010). For water depths greater than 100 m, floating foundations including spar, semisubmersible, and tension leg platforms are viable solutions, although their commercialisation is still at a preliminary stage because of costs.
Offshore installation is expensive. According to a recent study (Moné et al., 2017), the assembly and installation cost contributes approximately 20% to the capital expenditures of a bottom-fixed offshore wind farm. The installation costs are partly due to the rental of installation vessels and weather-restrictive nature of traditional marine operations (e.g. significant wave height ≤ 2.0 m). The turbulent wind condition is another factor that poses constraints. To avoid delays during offshore installation and to increase profit margins of the offshore wind industry, innovative and cost-effective methods for installing OWTs are desired. For instance, Sarkar and Gudmestad (2017) suggested an installation approach using a floating vessel with a floatable subsea structure for installation of monopile-type wind turbines. Guachamin-Acero et al. (2017) proposed another method for installing bottom-fixed wind turbines based on the inverted pendulum principle. Yet, these installation methods are not readily applicable to floating wind turbines.
For deepwater developments involving floating platforms in harsh environmental conditions which lie beyond well-established industry practices, model tests are usually required. The paper describes the different types of model tests and their respective objectives, scopes, and requirements. Different types of testing facilities are also described. The objective is to give an overview of various aspects of model testing, so the reader will come away with a better understanding of how and why model tests are performed and how they can best be used in projects.
The timing of tests and their interaction with the project schedule is also described. For example, model tests may be carried out early in the design for concept selection studies, or sometimes at the end of FEED for a specific concept application. Project tests are often performed at the beginning of detailed engineering to resolve any outstanding design issues or sometimes near the end of the project to confirm the effects of certain changes. These different test types have different methods, requirements, procedures and results.
Model tests may address installations, operations or performance of deepwater systems such as mooring and dynamic riser interactions or may generate benchmarking data for CFD. Depending on the type of tests, certain key aspects must be carefully controlled. Required test data and the cost-benefit trade-offs of different test objectives are discussed. Results and observations are given for several model testing applications of deepwater developments in Asia Pacific region and elsewhere. Examples of different types of tests are used to draw conclusions about the role of tests.
Looking ahead to the future, several deepwater testing basins are under development in different parts of the world. Limitations such as scale effects and basin boundary truncations are discussed. Ongoing research into novel model testing methods currently being carried out and their potential to improve the accuracy and reliability of full-scale predictions are pointed out. CFD or so-called numerical wave tank is a relatively mature tool which is gaining use in offshore projects and promises to overcome some of these limitations. Fortunately, improvements in available computing power and software are continually reducing the required computation time and cost. Both physical tests and complementary CFD simulations are required to obtain a complete picture of the full-scale performance of deepwater platforms. The need for full-scale measurements and design feedback is often over-looked but benefits future projects by closing the design loop to reduce future conservatism.
The primary goal of floating systems life extension efforts is to project how the system or components will behave in the future beyond the original design life. This predicted behavior can then be used to determine the practicality of the proposed life extension in terms of safety, environmental and economic risk. Often, these predictions are limited to reviewing inspection data (which has a limited ability to predict future response) or analysis (which is dependent on various assumptions). Measured data from in-situ monitoring systems provides accurate system response information which, in conjunction with mathematical modeling and inspection data, can be used to determine past and future behavior. The full potential of measured data for life extension activities has not been realized thus far.
Some uses of measured data in life extension efforts are illustrated through examples in this paper. The first example highlights ongoing fatigue assessment of a mooring line chain jack system using line tension measurements. The second example describes how uncertainty was greatly reduced in a polyester rope fatigue assessment by utilizing measured mooring line tension data. The third example demonstrates use of measured vortex induced motion response of a floating system to reduce the conservative assumptions provided during the design phase. The results of all of these examples show that measured data can provide insight into floating production system (FPS) response that cannot be attained otherwise, allowing for significantly reduced conservatism in life extension engineering assessments. Without the availability and use of this data it would be difficult to demonstrate the fitness for service of these facilities.
The examples of utilizing measured data to enhance life extension efforts provide concrete demonstrations as to how life extension of FPS components can be justified where uncertainty in analytical prediction is high. In such situations, demonstrating fitness for service beyond the design life would prove exceedingly difficult if measured data was not available. Continued service feasibility is most effectively demonstrated by augmenting inspection and analysis efforts with field monitoring data.
This paper presents a comprehensive dynamic analysis of a marine spar platform with various mooring system configurations. From a practical viewpoint, the mooring system configuration is managed by reel-motor devices that change cable lengths while keeping all cables under tension. The spar platform is anchored to the seabed by twelve mooring cables (in six cable bundle arrangements), and the domain that the cable-driven spar platform can be within is called the platform effective area. The analysis is based on a global frame of reference at the seabed and a local frame of reference at the platform center of gravity. Under the context of rigid body dynamics, the averaged values of the mooring cable tension are calculated through the use of a second norm measure. The platform dynamic response under unidirectional harmonic water waves and changeable submerged depths is investigated over the entire spar platform effective area. The minimum platform natural frequency at each location within the effective area is used as a measure of the platform degree of rigidity.
Spar floating marine platforms are often used for offshore operations such as oil and gas exploration and production and wind energy harvesting. A spar platform consists of a floating structure that is connected to a heavyweight spar and anchored to the seabed by a cable-based mooring system. The first spar platform in the oil industry was installed in the North Sea in the 1970s and used for oil storage and offloading (Bax and de Werk, 1974; Van Santen and de Werk, 1976). While the floating platform is exposed to the environmental loads, the mooring system has the objective of retaining the floating structures’ location. Commonly used mooring systems consist of three cables (Karimirad and Moan, 2012; Jeon et al., 2013; Muliawan, Karimirad and Moan, 2013; Muliawan et al., 2013; Si et al., 2014; Kim et al., 2014; Yu et al., 2015), four cables (Downie et al., 2000; Chen et al., 2001; Sethuraman and Venugopal, 2013), nine cables (Zhang et al., 2007; Zhang et al., 2008; Montasir and Kurian, 2011; Montasir et al., 2015), and twelve cables (Wang et al., 2008; Yang et al., 2012).
A number of researchers analyzed the dynamic response of spar platforms through the use of different numerical and experimental techniques. The spar platform motion was investigated by Ran et al. (1996) through the use of a higher-order boundary element method, and they compared their numerical results with the measurement data, showing good agreement. Jha et al. (1997) obtained an analytical prediction for wave drift damping and viscous forces that influence the dynamic response of spar platforms. The effect of nonlinear sea waves on the dynamic response of a spar platform was investigated by Anam and Roesset (2002) through the use of the hybrid wave, stretching, and extrapolation models. Using Morison’s equation, Anam et al. (2003) studied the differences between the time domain analysis and frequency domain analysis in predicting the spar platform slow drift response.
Liu, Weiwei (COTEC Offshore Engineering Co., Ltd.) | Wang, Jin (COTEC Offshore Engineering Co., Ltd.) | Huang, Jia (COTEC Offshore Engineering Co., Ltd.) | Liu, Yang (COTEC Offshore Engineering Co., Ltd.) | Li, Yang (COTEC Offshore Engineering Co., Ltd.)
In recent years, Spar platform has become one of the most attractive deepwater development concepts due to its superior stability and strong operability suitable for dry-tree drilling and production in a wide range of water depth from 300m to 3000m. A new concept Spar platform, namely Spar Drilling Production Storage Offloading or SDPSO, combining the advantages of the deep-draft classic Spar configuration with the capability of oil storage, will be studied in this paper. This new concept Spar or SDPSO doesn't rely on a subsea pipeline system for oil export, thus significantly improves the flexibility of technical solutions and decrease the overall cost for deepwater marginal field development. Unlike conventional ship-shaped FPSOs, the SDPSO uses the oil-over-water or oil-water displacement method for oil storage. This paper first will provide an overview of the oil storage and offloading systems of the SDPSO. In general, two methods can be used for offshore oil storage loading and offloading, namely oil-gas displacement method (commonly used in a conventional FPSO) and oil-water displacement method. Due to its economical advantage and efficiency, the oil-water displacement method has been widely used in fixed gravity based structures in the North Sea and offshore Canada. In principle, the oil- water displacement method for oil storage and offloading is simply based on the natural separation of oil and water by gravity as the density of oil is lower than that of sea water. Since the SDPSO is a floating platform, the wave induced motions of the floater may cause certain effects on the oil-water interface mixture and potential pollution risk in the water discharged into the sea when the sea water is displaced out by oil in the storage tank. This paper will discuss typical process flow diagrams (PFD) of the oil storage and offloading systems of the SDPSO and provide a new system design which not only retains the advantages of oil-water displacement method for oil storage and offloading, but also eliminate the potential risk of environmental pollution from the displaced sea water discharged into the sea.
A panel discussion at OTC focused on the lessons learned developing the Mad Dog field. On the first day of the 2017 Offshore Technology Conference, a panel of executives, project managers, and government regulators involved with the Mad Dog project in the US Gulf of Mexico (GoM) discussed the lessons learned in bringing the project on line. While the panel focused on several elements of the development of the Mad Dog field, ranging from seismic imagery to facility construction to the issues faced after first oil in 2005, a common theme of the seven panelists was the importance of collaboration and strategic alignment amongst every company involved in the project. The Mad Dog spar is designed to process 80,000 BOE/D and 60 million ft3/D of gas. BP operates the field and holds a 60% ownership interest.
AbstractOil and natural gas producers continuously strive to control costs, and that goal becomes even more important when market conditions are challenging. To maximize the return on their capital investment and continue to extract reserves on legacy fields, many owners and operators are looking for ways to extend the service lives of aging assets.The Neptune Spar was the first production spar platform in the world, when it was installed in 1996. Currently owned and operated by Noble Energy, the unit continues producing at Viosca Knoll 826 in the Gulf of Mexico. As the platform ages, there is an interest in extending its service life to allow continued operation in the field. As requested by Noble Energy, ABS Group initiated a life extension assessment project.This paper describes the process of the Neptune Spar life extension assessments and challenges encountered during the process. One of the critical aspects of the life extension process is regulatory approval. Since the life extension for floating production platforms is a relatively new trend in the offshore industry, the regulatory compliance process is still under development, and this project is providing a significant contribution to the development of guidance and criteria.The purpose of a life extension assessment is to understand the history of the facility and its current physical condition to determine its structural integrity and outline what is needed for the unit to be maintained for safe and responsible extended service. The life extension project began with a roadmap for life extension assessments that included conducting baseline inspections, reviewing historic inspection and repairs records, undergoing gap analyses that compared the spar's current condition with the original design premise and calculations, and performing additional engineering analyses.As part of the regulatory approval process, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) and the U.S. Coast Guard (USCG) require that a Certified Verification Agent (CVA) verify the entire process of life extension and submit reports that document findings and recommendations. ABS served as the CVA. During the life extension assessment process, ABS Group and Noble Energy consistently coordinated with ABS, BSEE and USCG.Based on the life extension assessments, ABS has granted class certificate for the life extension of this platform. The process of the spar's life extension assessment provides industry with a better understanding of the technical requirements for life extension of other floating production assets, which will have a long-term impact on future asset intergrity management for these types of facilities in deep water.