Abstract In August 2020 the Operator deployed a fully immersive On The Rig (OTR) Simulator for the execution of a Drill the Well On Simulator (DWOS) project on the semi-submersible Maersk Developer to prepare the crew to drill the 1st Petronas Deepwater exploration well (name redacted to Well X) offshore Suriname. The offset well data showed numerous downhole troubled time events, such as well control and stuck pipe in addition to other risks that required to be actively managed. With many of the crew being new to the rig, competence was identified as a key risk. The Operator engaged a DWOS program to ensure the rig crew competence was accelerated and project risks were understood and mitigated. This was achieved through realistic simulations, well/rig specific training and advanced human factors training, specifically designed to ensure the successful delivery of the well.

Abstract High reliability, high potential risk industries, such as aviation, have recognised through root cause investigations that most accidents are the result of human errors. The O&G industry is no different and drilling is particularly reliant on human actions and interactions. In August 2020, the organisations mentioned above deployed a fully immersive On-The-Rig (OTR) Simulator for the execution of a Drilling-Well-On-Simulator (DWOS) project on the semi-submersible Maersk Developer to prepare the crew to drill the 1st Petronas Deepwater exploration well (name redacted to Well X) offshore Suriname. The offset well data showed a high-risk probability of Well control and stuck pipe in addition to other risks that required to be actively managed. The business partners created a high-fidelity / fully immersive DWOS by programming and conducting rig and well specific simulations. A combination of leading simulator technology with advanced human factors and technical coaching accelerated crew competence. The overall impact of the DWOS was significant both in terms of learning and operational impact: The well was best-in-class in cost – (Cost Per Foot) and best-in-class in Schedule – (Days Per Thousand Foot). There was NO stuck pipe or well control issues. The operator has now recommended DWOS for all future complex wells, under a pre-defined criteria. Initiatives or enterprises are only successful if there is full support and coordinated collaboration between the requisite parties. Three groups collaborated closely on the delivery of this coaching and training project, namely: the operator, the hardware and software provider and a specialist coaching and training company, utilising an OTR drilling simulator. It had already been identified that there had been significant challenges on offset wells and that several substantial lost time events had occurred. The coaching and training modules would therefore need to be created to prepare the crews in threat and error management of the anticipated hazards and those well construction tasks that had historically been troublesome, in this area. Well X was the operator's first deepwater venture offshore Suriname, (Block 52), in ‘mid-water’ at 520 meters. Block 52 is located north of the coast of Paramaribo, Suriname's capital city and is situated in the prospective Suriname-Guyana basin where several major hydrocarbon discoveries have been made recently. Block 52 covers an area of 4,749 km² with water depths ranging from 50 to 1,100 meters. Well X was planned as a five-string design with a contingency Liner. The objective of the project was to explore, test and evaluate the potential of hydrocarbons and to obtain sufficient geological and geophysical data for future exploration in the basin of offshore Suriname. On completion of the drilling and data acquisition the well was to be abandoned. The dual activity semi-submersible, Maersk Developer, was chosen to drill and abandon the well. The Developer had completed a campaign in March and vast majority of the crew were new to the rig but were working on other D Rig designed rigs in the Maersk fleet.

Most of the offshore wind developments to date, globally, have been bottom-fixed foundations located in shallow waters (<30m water depth) and in close proximity to shore. However, as technology improves and as space for near-shore sites decreases, offshore wind development is projected to trend towards deeper waters. Floating wind is thus expected to become one of the leading renewable energy sources over the next decade or so. Notably, the success of pilot projects in Europe has confirmed the viability of floating wind technology, drawing in additional developers to the market. In the United States, there is a significant potential for floating offshore wind off the coast of California, Maine, and Hawaii. While the majority of current floating wind activity is concentrated in <200m water depth, further technology improvement coupled with experience from floating oil and gas developments will lead to even deeper floating wind projects in the future. One key aspect for floating wind technology is the floater foundation that will support the wind turbine assembly. The entire unit will be moored to the seabed and be subject to challenging environment conditions throughout its service life (akin to a floating oil and gas production facility). There are several floating wind concepts currently in the market - a handful are field-proven at pilot project scale but the majority are still in development phase, each with their own unique offering. The purpose of this paper is to perform an independent qualitative assessment of the current floating wind concepts. The assessment will focus on aspects related to technology readiness, design complexity and scalability, material selection, constructability, installation, operations, and maintenance. This paper provides the offshore wind industry with an unbiased opinion on available designs as well as an insight into perceived challenges for future developments. As a disclaimer, it is noted that Wood has utilized public-domain information for this study and has no preference towards any existing floating wind concepts or designs.

Severe drill stem vibrations could leads to excessive damage to the bottom hole assembly causing an increase in nonproductive time. Different drill stem vibrations models are used to predict and avoid resonance regions by optimizing the selection of bottom hole assembly components and operating parameters such as weight on bit, and surface RPM. In addition to avoid the resonance regions, specialized tools have been developed to reduce vibrations. However a complete understanding on how to mitigate vibration and its effect on drilling performance is still lacking. This study investigates the cause of drill stem vibrations, its effect on drilling performance, and the effect of including vibration reductions tools in the bottom hole assembly design in several recent drilled wells in the North Sea. Vibration damping tools used in this study were able to reduce both lateral and torsional drill stem vibration compared to a well with no vibration damping tool. Torsional drill stem vibrations tend to increase through rich sand zones causing an increase in lateral vibrations. The impact drill stem vibrations have on drilling performance was identified through rate of penetration. As lateral vibration intensity increases, instantaneous rate of penetration decreases.

To ensure safe and reliable operation in a robotic oil drilling system, it is essential to detect contact events such as impacts and slips between end-effectors and workpieces. In this challenging application, where high forces are used to manipulate heavy metal pipes in noisy environments, acoustic emissions (AE) sensors offer a promising contact sensing solution. Realtime AE signal features are used to create a multinomial contact event classifier. The sensitivity of signal features to a variety of contact events including two types of slip is presented. Results indicate that the classifier is able to robustly and dynamically classify contact events with >90% accuracy using a small set of AE signal features.

Abstract Over the last decades we have seen many improvements in drill floor automation. Common for many of these have however been more in line of "make a machine to duplicate manual labor". This is about to change. Over the last 5 to 6 years more and more companies and resources have been focusing on creating fully automatic systems, and in the last couple of years we have seen the introduction of fully robotized systems. This paper will highlight some of the vast improvements seen in Health and Safety as well as efficiency measured in both time and money when using robotics in the drilling operations. This will be true for most, if not all, drilling structures designed for land or offshore operations either used for drilling for hydrocarbons or not. We will discuss how fully robotized drill floor, and even small partly intelligent tools can make a big difference, for both safety and cost savings. This effectiveness and safety aspect will be further improved when using autonomous decision making systems. With autonomous system we mean that the systems itself will have the ability to decide how to perform a given task more safely and with a higher efficiency than a preprogrammed task.

The present study is devoted to discrepancies between experimental and theoretical runup heights on an inclined plane, which have occasionally been reported in the literature. In a new study on solitary wave-runup on moderately steep slopes, in a wave tank with 20 cm water depth, detailed observations are made for the shoreline motion and velocity profiles during runup. The waves are not breaking during runup, but they do break during the subsequent draw-down. Both capillary effects and viscous boundary layers are detected. In the investigated cases the onshore flow is close to the transitional regime between laminar and turbulent boundary layers. The flow behaviour depends on the amplitude of the incident wave and the location on the beach. Stable laminar flow, fluctuations (Tollmien-Schlichting waves), and formation of vortices are all observed. Comparison with numerical simulations showed that the experimental runup heights were markedly smaller than predictions from inviscid theory. The observed and computed runup heights are discussed in the context of preexisting theory and experiments. Similar deviations are apparent there, but have often been overlooked or given improper physical explanations. Guided by the absence of turbulence and irregular flow features in parts of the experiments we apply laminar boundary layer theory to the inundation flow. Outer flows from potential flow models are inserted in a nonlinear, numerical boundary layer model. Even though the boundary layer model is invalid near the moving the shoreline, the computed velocity profiles are found to compare well with experiments elsewhere, until instabilities are observed in the measurements. Analytical, linear boundary layer solutions are also derived both for an idealized swash zone motion and a polynomial representation of the time dependence of the outer flow. Due to lacking experimental or theoretical descriptions of the contact point dynamics no two-way coupling of the boundary layer model and the inviscid runup models is attempted. Instead, the effect of the boundary layer on the maximum runup is estimated through integrated losses of onshore volume transport and found to be consistent with the differences between inviscid theory and experiments.

Abstract Seabed data acquisition methods offer numerous advantages over towed streamer data. These advantages can lead to improved static and dynamic reservoir characterization. By recording complete vector field data at the sea floor with full azimuth acquisition improved shallow resolution, signal-to-noise ratio, spectral content, deep imaging and 3D illumination can be achieved. Also in the presence of obstacles such as production facilities a regular coverage can be assured. Autonomous node technology has been developed to a fully commercial system. It has demonstrated improved imaging of complex reservoir with both pressure (PP) and converted shear (PS) with stable and consistent measurements achieved by very well planted nodes into the sea floor and full azimuth acquisition with densely sampled shots. It has been experienced that the background response from well planted nodes can be repeated in a 4C-4D scenario when the coupling conditions are the same. The vector fidelity in the node system will secure this behavior. In addition, the accurate positioning and re-positioning of the nodes under realistic water depth ranges gives positioning accuracy close to permanently buried cable systems. An experiment performed on the Volve field in the North Sea with pairs of nodes planted side by side clearly confirmed the high degree of stability in the coupling and the repeatability of the measurements from all components. At 100 m water depth all the planted nodes were within a short radius around the pre-plot position. A cost sensitivity study of different 4C-4D node scenarios depending of field size, water depths and node spacing indicates that, for larger field sizes (300-600km2 receiver coverage), the alternative use of nodes could be significantly more cost effective than permanently buried cable systems. Moreover, there are advantages linked to the acquisition geometry, operation, zero equipment life time risk and low initial investment. Introduction Marine seismic exploration and reservoir imaging have been through numerous stages of adjustments and improvements. Towed streamer surveys from 2D to 3D and now to 4D dominate the offshore seismic survey with a well established technology which remains the most common acquisition with narrow azimuth coverage. New techniques such as " single sensor recording?? (Egan et al, 2005), " over-under?? (Singh et al, 1996) and " wide azimuth?? (Campbell et al, 2002) have recently delivered impressive results. These techniques have raised the cost and complexity to more traditionally " simple?? towed streamer operations.

Owing to complexity and dynamism of the industrial settings, the business environment today is more prepared to adapt different competitive strategies to retain profitability and growth (see for instance, Click & Duening, 2005; Tidd, 2000; Wang, Heng, & Chau, 2007). Smart use of cooperative technologies and establishment of prudent business-to-business (B2B) partnerships are very central to manage risk when business activities are exposed to a much wider range of uncertainties (Shaw, 2006; Wang et al., 2007; Wroblewski, 2002). This is particularly so for high-risk businesses such as oil and gas (O&G) exploration and production (E&P), which is far more sensitive in socio-economical and political terms. This chapter presents such an emerging collaborative and dynamic network environment within the O&G industry on the Norwegian continental shelf (NCS) through a case study. It provides a background of the industry, describes the organization of the network, its structure, and the active strategic components. At the end it also highlights some of the major challenges that need to be addressed in the establishment of a fullyintegrated and fail-safe network and an operational enterprise to manage complex assets. This is based on an ongoing industry-wide new development process termed integrated operations (IO) commenced very recently in 2004-2005 dedicated to establish smart offshore asset management practices on NCS by 2015 or so (OLF, 2003).