Back analysis of foundation piles is an important aspect of a project, as it can allow for refinement of soil parameters, leading to pile holding capacity variations, and a more accurate fatigue life assessment. Back analysis of pile driving data to determine the capacity of an axially loaded pile, such as for a jacket structure, is a well-developed process, with the results of pile driving data directly applicable to axial foundation response. However, for mooring piles, where the loads are dominated by lateral forces, determining the capacity is more complex as the results of driving data are not directly relatable. Offshore mooring piles are opened-ended steel tubular piles, with diameters typically ranging between 1 m to 2 m, with a padeye (mooring chain attachment point) located at some point along the pile, usually within the upper third. The piles are driven into the seabed with an underwater impact hammer, or vibratory hammer, and are used for mooring floating structures. This paper presents a methodology to carry out a back analysis of mooring pile capacity based on pile driving data. The process involves two stages, the first is to assess the self-weight penetration of the pile, which will allow clarification of the design shallow soil properties; the second stage is to compare the pile driving data, with the estimated soil resistance to driving, to gain an understanding of the deeper soil properties. The procedure presented within this paper was applied to an assessment offshore South East Asia, a case where location-specific data were not available but were within 500 m of the mooring pile locations. The procedure was used to verify that the piles were suitably designed against the given loading conditions, as the soil data was not co-located with the mooring pile locations. The process forms an important aspect when considering the future of offshore moorings, specifically looking ahead towards floating offshore wind, potentially offering refinement of design factors, verification of pile capacity, reducing offshore exposure time, and optimizing the fatigue life of piles following driving.

Fatigue is one of the key design considerations for moorings, risers, and umbilicals in offshore floating systems. Due to differences in materials, components, configurations, and functionality, these slender structures have distinct drivers for fatigue performance. On the other hand, they also share a number of the same challenges. Typical slender structure design configurations include taut and catenary mooring systems; steel catenary riser, steel lazy wave riser; and catenary, lazy wave, and pliant wave configurations for umbilicals. This paper introduces the fatigue performance drivers for mooring lines, risers, and umbilicals. The paper also compares the fatigue performance of moorings, risers, and umbilicals, and provide cross-disciplinary guidance to the integrated design of floating systems, thereby helping improve the overall system reliability. Moorings, risers, and umbilicals demonstrate quite distinct fatigue characteristics but share some similar challenges. Mooring fatigue performance is influenced by tension and corrosion. Chains in fairlead locations and on the bottom are the most critical fatigue locations for mooring fatigue. Recent fatigue test data show that mean tension significantly impacts chain fatigue and thus whole mooring system fatigue life. Fatigue is a significant challenge for riser design due to tension and bending. The hangoff and touchdown zones are usually the most fatigue critical areas for risers as well. Similar to the mooring design, corrosion contributes to riser fatigue. Riser configuration, internal fluid slugging, as well as seabed stiffness significantly affect riser fatigue performance. Besides tension and bending, one of the specific features for umbilical design is the interaction between the different elements within an umbilical cross-section, which significantly impacts its life. Since this effect is more significant in regions with higher tension and curvature, the hang off region is usually the critical area for umbilical fatigue. The offshore industry is moving towards integrated design and systematic approaches. Although there is abundant literature discussing the fatigue of mooring, risers, and umbilicals separately, there is very limited published literature comparing the performance of these three types of slender structures. This paper can serve as a useful reference for a floating system integrated design. Cross disciplines can also benefit by leveraging the design philosophy and mitigation strategy of different types of slender structures.

Offshore Floating Wind is finally emerging as a promising source of Renewable Energy, but the Industry still faces important challenges. Among these, the impact the floater's motions have on the product life-cycle performance still requires evaluation and validation. In this sense, the industry has struggled to define an approach that minimizes the Levelized Cost of Energy (LCOE). The reasons for this, among others, are that each floater typology induces different motions on the nacelle equipment, each metocean site conditions are different, and the wear at the nacelle depends on the turbine model and manufacturer. Hence, the industry recommendations have so far usually limited the maximum longitudinal accelerations at the nacelle to 0.3-0.4g, and the maximum roll-pitch combination is set below 10°. The induced motions add dynamic loading, wear down the mechanical equipment, produce fatigue damage on the structural members and are a source of potential downtimes, due to machine failures or simply due to unacceptable accelerations at the nacelle. Therefore, the different components of the turbine should be reinforced, increasing the CAPEX; or the maintenance and repair activities with its associated costs should increase; being both a possible combination. The purpose of this paper is to analyze the different costs items associated with more or less conservative approaches with regards to the motions at the nacelle highlighting the combination of accelerations, operational weather windows, construction and maintenance strategies that can lead to the optimum LCOE. Several response spectra of accelerations at the nacelle will be obtained for two different floaters, namely; a spar and barge preliminary sized for the DTU-10MW reference wind turbine. The effect of the turbine controller on the motions is not considered. For different acceleration cutoff values, the energy produced is estimated.

Mooring systems are integral and sophisticated components of offshore terminals, which are vital elements of the hydrocarbon supply chain. The significant risks to asset integrity and personnel safety associated with compromised mooring systems makes it of paramount importance to evaluate their reliability in multiple scenarios. Because much larger hawser forces occur during sudden changes of wind direction than during steady-state storm conditions, fully-coupled hydrodynamic analyses and simulations were conducted for a 420,000 DWT tanker connected to a single anchor leg mooring (SALM) buoy when subjected to a sudden squall event. The global performance of the SALM and tanker coupled model was evaluated based on consistent analysis of extremes while solving the equations of motion for a system of rigid bodies, each oscillating in six-degrees-of-freedom (DOF) in time domain. The dynamic model conveniently and consistently calculated and documented vessel responses for motion and mooring tension under the environmental conditions specified in each loadcase. A range of wind, wave, and current headings were analyzed to capture the most onerous design conditions for the tanker; and the maximum vessel motions, and mooring line tensions were determined. The analyses were carried out for the vessel in its loaded and ballasted conditions, as well as for two water depths. Results showed that in winds over 50 knots, weathervaning of the tanker to the position of least resistance produced mooring and motion responses exceeding the safe working envelope, while break-out due to tautening of the bow's mooring hawsers occurred in winds over 77 knots. Significant buoy overtopping was also observed during the 3-hour time domain simulations. Mitigations to avoid break-outs and maintain a safe-working environment included a constant stern thrust of 50 tonnes throughout the loading/offloading operations, resulting in a 30% reduction of the total bow mooring force.

High Modulus Polyethylene (HMPE) fiber ropes have been widely employed in a large variety of marine and onshore load bearing applications, but not yet in permanent offshore mooring systems due to their well-known high creep behavior. The Lankhorst Gama98 ® HMPE mooring ropes based on low creep Dyneema ® DM20 fiber were recently introduced and certified by ABS for the offshore WindFloat Atlantic project's mooring system at a depth of around 100m, which is the first time such HMPE fiber ropes have been used for permanent mooring. Compared with the conventional application of fiber ropes, usually employed as middle segments of mooring lines, the application of HMPE ropes as top segments directly connected with the platform in shallow water creates more challenges from the impact of temperature, UV and marine growth. For the permanent mooring of WindFloat Atlantic, the HMPE mooring rope was incorporated in the catenary mooring system by Principle Power to transfer the restoring force generated by the bottom chain weight in an efficient and direct manner to the floating platform. This lightweight mooring line enables lower pre-tensions while maintaining the same station keeping performance and excellent fatigue life. This ultimately drives down the pulling capacity requirements for installation of the mooring system and hook-up of the platform. Lessons learned from this application could result in a more efficient approach to HMPE mooring line installation. With such groundbreaking application, the HMPE rope is being demonstrated as a permanent mooring component and its performance assessed in this wind energy project, which may benefit the offshore wind industry. It may also be useful to oil and gas in a permanent use application context. This paper presents (i) the ABS process details in assessing the proposed HMPE ropes with DM20 low creep fiber for meeting class requirements and WindFloat Atlantic project specific needs, and (ii) address the offshore industry concerns with HMPE ropes such as creep, creep rupture, UV effect, and marine growth.

Mooring line tension monitoring is required for permanently moored floating offshore platforms by some regional regulators and classification societies. This requirement is typically satisfied by installing physical sensors that directly measure the line tension. Experience shows these sensors have relatively short life compared to the platform operational life and consequently they need to be changed several times thereby increasing the operational expenses. It is also possible that changing the sensors in the field may not be feasible due to access and safety issues or it may be prohibitively expensive, which could lead to the platform operating without meeting the regulations. This paper presents a machine learning based model, which we call ‘virtual sensor’, for predicting the mooring line tensions based on the platform’s heading, horizontal position and six-degrees-of-freedom (6-dof) rigid body motions. The model’s development and testing are demonstrated with the help of data generated through numerical simulations of a permanently moored semi-submersible. When deployed in field, the inputs to the virtual sensor would be obtained from the global position system (GPS) and accelerometers. Both the GPS and accelerometer are cheaper to install and maintain, reliable and easy to replace. The neural network model is pre-trained using a dataset of 5000 static simulations and further fine-tuned with 48 dynamic simulation cases. Model performance on four mooring lines are presented in the study. The accuracy of the model was assessed by determining the percentage of predictions with errors within ±5% of the simulated mooring line tensions. Three of the mooring lines achieved accuracy greater than 90% and one mooring line achieved 77% accuracy. The relevant limitations of the study and future work are discussed in the paper.

Engineering Critical Assessment (ECA) has become essential for establishing if a mooring line in service is fit for continued service when low fracture toughness in some components is suspected or inspection results may suggest possible presence of discontinuities. Existing ECA codes and standards such as BS 7910 has rather limited stress intensity factor (K) solutions suitable for this type of applications, e.g., elliptical crack stress intensity factor solutions valid for a short crack regime with a/D ratio far less than 0.1 with different aspect ratios other than a/b =1. Here, D refers round bar diameter and a crack depth (minor axis) and b crack half length (major axis). As a result of a recent joint industry project (JIP), referred to as Mooring Component Assessment (MCA), a comprehensive set of K solutions have been developed for covering crack size a/D from 0.005 to 0.15 which associated with existing K solutions allows to cover a/D from 0.05 to 0.6, along a unified treatment of local stress gradients, e.g., at knuckle positions, for supporting ECA of mooring components and chain links. These K solutions are presented in a set of simple parametric forms and can be readily used for ECA assessment of shackle and chain-link components.

Prelude FLNG ("Prelude"), the largest offshore floating facility ever built, was constructed in Geoje, South Korea, requiring a 3,200nm ocean tow to its installation location 475km north northeast of Broome, Western Australia. A team of station keeping vessels then took control of Prelude to accurately hold her in position above the pre-laid moorings for mooring hook-up operations. Planning and executing the tow, station keeping and mooring hook-up operations for mega floaters in remote locations requires precise planning, bespoke solutions to unprecedented challenges, comprehensive testing over a prolonged period and a global team with a diverse skill set. Overcoming key challenges required extensive engineering coupled with state-of-the-art vessel simulations, a bespoke mooring handling system, and full-scale winch wire testing. The result was a safe, successful and efficient operation demonstrating the industry's ability to execute the unprecedented challenges of projects in the search for economic development of remote and challenging reservoirs.

Objectives/scope Polymeric Fiber Ropes have been used extensively for Permanent Offshore Deep-Water Mooring systems. High strength polyester ropes have been used for FPSO mooring with proven performance of more than 20 years. Fiber rope have no corrosion issues and superior performance in fatigue. There is also a need to evaluate the applicability of fiber ropes instead of steel chains and/or steel ropes used on top and mudline segments. Long-term performance and integrity with the benefit of a lower Total Cost of Ownership (TCO) can be expected. The OTC 24025 paper addresses integrity issues on permanent mooring systems. Authors concluded that a great majority of premature failures/damages are associated with steel components such as chain, wire ropes and connectors, and not with fiber rope segments. It is also necessary to assess long-term performance and environmental resistance of synthetic rope regarding its use in top side, mudline, as well as shallow water mooring for the growing business of Marine Renewable Energy and Offshore Wind Farms (FOWT). It is also important to study the lifetime assessment of polyester mooring ropes. FPSO operators are also considering life extension of existent mooring systems installed over 10-15 years ago evaluating the impact of creep, hydrolysis and other environmental issues such as UV and marine life growth.

The paper focuses on the history of the development of the Floating Production Storage and Offloading (FPSO) system and its evolution to be the most adaptable and versatile of floating production systems. These facilities have been deployed in a variety of water depths and metocean conditions in almost every offshore oil producing basin in the world, with a large range of topsides throughput for both oil and gas. The paper has summarized the development of the FPSO system as a function of time, water depth, location, system, type and complexity to illustrate its adaptability to offshore producing basins worldwide. The paper also provides a brief historical description of the evolution of the system by decade, highlighting key projects and technologies and their development over the years. The paper also looks forward to the short-term future of FPSOs in the Oil and Gas industry based on trends and forecast, and the future development especially related to digitalization and carbon footprint reduction. The paper also speculates on the possible application of the system and component technologies to support alternative energy development in the future.

Floating Production Systems (FPS) remain on station many years without dry docking. The mooring lines, which ensure station keeping, are designed to last the entire service life of the FPS. However, many mooring line failures or premature replacements have occurred in the past [ 1 ]. Most existing mooring line failure alarm systems utilize subsea load cells or inclinometers, which are expensive to maintain or replace and are not sufficiently reliable [ 2 ]. Hence, this paper presents a new methodology to assess the mooring integrity by means of position measurements only, which is less expensive and potentially more reliable. This methodology for mooring line integrity assessment was developed as part of the LifeLine Joint Industry Project and focuses on application for a variety of FPSOs with different characteristics. The methodology contains two different approaches for the position data processing. One approach is an event-based method. It attempts to identify failure events by the semi-instantaneous shift in the mean static offset of the floater. The second approach is a status-based method. It assesses the integrity of the mooring lines by keeping track of the unit position in a longer time frame. In this paper the methodology will be described in general and the validation results will be presented. Validation is done by using simulated blind tests as well as in-service measurements of several FPSOs. The validation results of blind tests and in-service measurements are presented for 3 floaters. It was concluded that all mooring line failures were identified by the LifeLine methodology within the target time of two to twelve days, and in all cases the correct bundle with the broken mooring line was identified. This research is a big first step towards realizing a more reliable, more sustainable and less expensive mooring line failure warning system than the existing state-of-the-art systems. Further validation efforts will be continued in the LifeLine JIP, and a first prototype of the LifeLine system will soon be implemented on an FPSO in the field.

Unlock marginal and stranded reserves in shallow waters that are far away from existing infrastructure. The solution is a system that employs a jack-up based mobile offshore production unit (MOPU) in combination with a modular subsea storage system. The storage system is an unmanned solution that is designed with an integrated offloading system. Integrated into a single, integrated system, this robust solution encompasses all necessary components thus reducing both CAPEX and OPEX. The case is based on standard MOPU designs with compact process modules to reduce weight and cost. Additional cost savings come from standardization and placing fully integrated components subsea. An integrated process train ensures the right quality of oil or condensate is sent to the subsea storage tanks, ready for tanker pick-up. This paper also describes how the associated gas will be handled. The field-proven offloading system is linked to storage, ensuring correct metering and safe mooring for any vessel. Combining modular subsea solutions with field-proven components gives operators access to technologies that provide an increased return on invested capital. The storage system is developed based on existing storage solutions. It is an energy-efficient system with a low environmental footprint. Recent engineering studies and testing have proven the feasibility of operating a subsea storage unit with a flexible membrane defining the horizontal interface between oil and seawater. This paper presents new results from a downscaled subsea storage system model testing conducted by an original equipment manufacturer (OEM) together with a major operator. The innovative cluster design will enable re-deployment of the storage units, which opens new combination possibilities with MOPU's. Interfaces between the various system components have been streamlined to create an integrated system and when deploying these different building blocks in that way, a custom field solution can be provided for marginal field developments – including an option to modify and re-deploy. Research has shown that replacing the floating storage and offloading vessel (FSU/FSO) with subsea storage reduces offshore manning and the environmental footprint. This technical paper explains the modularity and the economics of an installation-friendly design. Lower complexity, in combination with cost-effective installation, introduces new opportunities for field developments. The integrated solution is also designed with the option to operate below wax appearance temperature and can make even smaller field developments profitable at a lower cost, in an energy-effective manner, and with a low environmental footprint. With this new solution available, the market can take a whole new view on small pool developments.

Over the last decades, a number of mooring incidents have been reported in the public domain by conference papers and safety alerts. Mooring chain corrosion and fatigue have been reported as dominant incident triggers for these mooring incidents. Corrosion development is closely related to the locations of the mooring site. Fatigue is related toenvironmental conditions as well as mooring configuration for the mooring line load. This paper provides a review of the environmental conditions and water quality at offshore mooring sites. Important factors affecting mooring line load and load bearing capacity (mooring line degradation) are investigated. The ship-shaped FPSOs,as a dominant type of floating installationsand with more than two hundred of them currently in service,are the focus of this paper. The performance and uncertainties associated with the mooring system of the ship-shaped FPSO are evaluated.The paper provides recent industry advances onmooring performance simulations, monitoring and mooring incident identification techniques. It is recommended that risk-basedmonitoring and inspectionof mooring system can play an important role in improving mooring reliability and operational efficiency. The key elements includeidentifying critical directions of environmental loads, most loaded mooring lines, and the segments of the mooring line thatsubject to heavy corrosions. Systematical data collection, data sorting,data sharing and optimization of algorithm for anomalyidentification play important roles in effective monitoring.

Quality inspection costs may vary depending on criticality and complexity of the components being manufactured. As a crude estimate, asset owners, operators, or EPC contractors may spend up to 5% of the cost of their components on inspection oversight. Manufacturing data are usually captured in a document referred to as Manufacturing Record Book (MRB) which is at best an enormous collection of scanned records. A digital framework was developed for Appomattox mooring components in form of a database with logical links among relevant records. This database is fully searchable to the finest level and guarantees traceability from the final product to its sub-components and all the way back to raw material manufacturing. This database is custom-made and is comprised of several bases which follow through natural manufacturing process for the specific product. Logical links are made for each accessory at different stages using its unique designated identification (ID). As such database is generated on the go as the component is processed, it gives manufacturer and end customer a strong Quality Control tool as well as an integrity management platform. Appomattox mooring inspection records were used as a case study to showcase robustness and flexibility of the developed database. Reference is made to [ 1 ] for general lessons learned from Appomattox mooring delivery.

Floating offshore wind turbine technology, much of it developed domestically, is rapidly advancing and is in the early implementation phase, while floating substation technology is still at an early development stage. This study presents novel floating wind power substation platform designs for deepwater wind farm applications. Two types of floating substations configurations are considered to compare technical and cost performance: a semi-type "X-WindStation" and a TLP-type "TX-WindStation". The floating substation platforms are considered for a 200 MW wind farm located in 100 m (328 ft) water depth off the Northeast coast of the United States. The floating substation supports a two-deck electrical power facility that provides sufficient electrical power equipment layout area and includes temporary quarters. Both floating substation platforms are evaluated for global performance and mooring systems (catenary for semi-type and tendon for TLP-type) with the site design metocean conditions for the extreme and survival storm seas. The results are assessed in accordance with industry standards ABS and API, and offshore engineering practices. Capital expenditure (CAPEX) of both substation platforms for a 200 MW farm is estimated by including the electrical substation, platform hull, mooring lines, anchors, integration, installation and commissioning costs. Installed CAPEX costs of the platforms show that the semi-type substation platform cost is lower than the TLP-type cost for the case where each tendon has a dedicated anchor, whereas the cost for the TLP-type with two tendons sharing an anchor is highly comparable to, if not less than, the semi-type platform.

The Turret Mooring System (TMS) for the Shell Prelude FLNG (Floating Liquefied Natural Gas) facility consists of a Top Mounted Internal Turret (TMIT) integrated at the bow of the FLNG hull. Permanently connected to the seabed through a dedicated mooring system, this Turret allows the FLNG facility to passively weathervane in response to prevailing weather conditions and enables transfer of fluids and utilities (in both directions) between the subsea wells and FLNG topsides. This paper describes the challenges faced during the engineering and construction of the most challenging TMS ever executed to date. Prior to Prelude, SBM Offshore (SBM) had designed for Shell a TMS suitable for a large range of gas compositions from a portfolio of remote offshore gas fields, including North-West Australia, in water depths ranging from 165m to 1,350m, with the generic FEED vision "engineer one, build many". The Prelude TMS was finally developed with a detailed design to meet the specifics of the 250m field water depth and to remain safely on station for 25 years in cyclonic weather conditions. To achieve the robust design target, field proven solutions were revalidated for application at a greater scale, for a longer design life, harsher environment and the high reliability demands of the project. The execution strategy followed the requirements of TMS contractor direct and end Clients. The TMS, located very close to the bow, moors the 488m long, 74m wide Prelude FLNG hull. The system will ultimately accommodate 8 production risers, although only 4 are presently installed. The mooring system design is governed by the 10,000-year storm, resulting in a weathervaning system comprising 40 bogies, 40 radial wheels and 32 lower pads transferring the load to the hull. The mooring arrangement is composed of 4 bundles of 4 lines each, with 175mm R4 chains at top and bottom, and a mid-water section of 162mm sheathed diameter steel wire rope. Several challenges have resulted from the requirement to comply with a complex set of codes and standards, the severity of the cyclonic conditions, the record size of the FLNG hull, and from the required capacity of mooring components pushing beyond the existing industry experience base. Lessons learned from a selection of key challenges encountered during the engineering and construction of this one of a kind TMS will be presented with a view to facilitating future developments offshore North West Australia.

This paper presents a multitude of lessons learned during the 5 years spent on the design, manufacturing and delivery of the on- and off-vessel mooring components for the Appomattox semi-submersible. Appomattox is Shell's newest and largest deepwater oil & gas production asset in the Gulf of Mexico (GoM). It was successfully moored about 260 kilometers Southeast of New Orleans, in June 2018 using a 16-point chain-polyester-chain mooring system. It was the culmination of the work done by a dedicated team of Shell civil-marine engineers, mooring equipment suppliers and an offshore installation contractor. Shortly after completion of mooring lines hook-up operations, the polyester ropes were pre-stretched, and the FPS was moved into position for the start of the Steel Catenary Riser (SCR) system installation. Appomattox started production in May 2019. The mooring equipment has so far been performing as expected. The delivery of Appomattox mooring components was particularly challenging due to an unusually large number of stringent constraints including: 40-year design life, first application of fairleads with underwater chain stoppers in the GoM to mitigate out-of-plane chain link bending fatigue, polyester rope properties fine-tuned to ensure that installation and in-service requirements are met, stringent inspection oversight to enforce project-specific requirements, Thermal Spray Aluminum (TSA) on portions of the platform chains and novel chain handling equipment and method for mooring lines hook-up operations, just to mention a few. The design of the overall system and management of the mooring equipment vendors was performed using mostly in-house resources. The paper starts with some general information about the Appomattox development. The three subsequent sections present the mooring system, the delivery team and the overall timeline. The lessons are then organized in sections by mooring component types (on-vessel, polyester ropes, chains, and various connectors). Some reflections on how stakeholders influenced certain characteristics of the mooring components are disseminated throughout the paper. The paper also includes some observations about how the equipment performed in the field even though the lessons learned about the commissioning and offshore installation are left for a separate future paper.

This paper is part of the special OTC session "Floating Memories-Look Back to Leap Forward" intended as a historic retrospective of the evolution of the four major types of floating production platforms: Floating Production Storage and Offloading (FPSO), Semisubmersible (FPS), Tension Leg Platform (TLP) and Spar, from their inception to the present day. The session includes a look ahead to the future of these floating platforms and what it will take to sustain their commercial viability as they adapt to headwinds from continuous volatility of oil and gas prices and competition from onshore tight oil projects. This paper's focus is the Semisubmersible Floating Production System (FPS). It chronicles the forty five year progression of FPS technology from its humble beginnings in 1975 as a converted Mobile Offshore Drilling Unit (MODU) deployed on the Argyll field in the North Sea in 80 m of water, to Appomattox, the most recent FPS, that began production in 2019 in 2250 m of water in the Gulf of Mexico (GoM) . It also touches briefly on the evolution of the FPS hull, mooring and riser systems and addresses future trends and prospects. From Argyll to Appomattox

This paper presents the overview of the Pre-Service operations for the Aasta Hansteen field development. The paper also covers the execution challenges, supporting engineering and procedures followed for the various activities. The Aasta Hansteen Field development at a water depth of 1300m is the deepest field on the Norwegian Continental Shelf (NCS). The field is remotely located north of the Arctic Circle, in a particularly harsh environment 300km off the coast of Northern Norway, with 140km to the closest offshore installation. In the past, the pre-service marine operations for Spar platforms were completed at the offshore field locations. The Aasta Hansteen development presented the opportunity to complete the entire pre-service operations in the sheltered waters of the deep Norwegian fjords, making it a unique, first-of-a-kind inshore pre-service operations for a Spar platform ever executed. This advantage also helped to significantly reduce the cost and complexity of the pre-service operations effort for the project. There were several firsts in the industry for the Aasta Hansteen Spar platform, namely; Largest and heaviest Spar delivered, First Spar in Norwegian waters and subject to Norwegian rules, first full pre-service scope inshore in a fjord, first requirement for Structural Tank Inspection on a Spar Hull, first requirement for a Submergence Test, largest topside catamaran mating at 22,500 Te. Many of these firsts heavily influenced the planning and execution of the Pre-Service Operations for this project. The significance of these are also highlighted in this paper.

Mooring systems remain an important component of an overall field development. There are numerous sources in literature describing challenges with mooring systems as well as potential solutions. The goal of this paper is to present a number of new technologies which can be applied jointly in an integrated framework to monitor integrity of subsea mooring components. The paper will cover (1) direct tension measurements using Vibrating Wire Gauges, (2) warning systems based on anomaly detections from GPS measurements and (3) mooring line force estimation method and fatigue using time-domain simulation methods. Vibrating Wire Gauges are a potential alternative to the use of in-line load cells or inclinometers for measuring mooring line tensions. These sensors have a proven track record in the Geotechnical Industry. A sensor dedicated for the offshore industry has been developed. The main benefit of this type of sensor is the ease of retrofitting in an offshore environment. Long-term stability tests and dynamic tests were executed and will be presented. Procedures for installation and maintenance were developed. GPS measurements have widely been used in the industry to identify mooring failures. Post-processing methods of these measurements range from application of watch circles to Artificial Neural Networks. However, there remain important challenges with performance of these warning systems under the influence of environmental loads. The authors will show a basic concept which can overcome these limitations. High accuracy floater position and motion measurements can be used in combination with a numerical model to determine mooring line forces in the field. This approach combines the numerical models used in the design with onboard integrity and maintenance procedures. The technical and organisational challenges of such approach are discussed. An onboard system able to capture system drift is used to update the numerical model and correct for deterioration of the mooring system over time. In-service measurements have been used to demonstrate and validate the concept. The methodology has been implemented and installed on an offshore asset which will become active in Q1 2019. A number of industry solutions for mooring line integrity methods have been compared. All presented solutions have a role in the total mooring subsea integrity management program. Integration of these components together or supplemented with numerical analysis can be used to develop an overall mooring subsea integrity management plan and philosophy.