bluuebunny/crossref_metadata_2025_split huggingface dataset:
Face au cyclone Irma ! Le rôle des populations dans la gestion de la crise à Saint-Martin (Petites Antilles, îles du Nord)
Authors: Defossez Stéphanie , Gherardi Monique 
Published: April 2020

L’intense saison cyclonique 2017 dans l’Atlantique Nord a rappelé l’exposition de l’arc Antillais à ces phénomènes parfois dévastateurs, illustré par le cyclone Irma qui a provoqué de lourdes pertes sur les îles françaises de Saint-Martin et Saint-Barthélemy. La phase post événement donne parfois lieu à un retour d’expérience (RETEX), lequel rend compte des étapes et processus de gestion de l’événement. Le RETEX est largement mené auprès des institutions mais laisse peu la parole aux populations. Cette étude relève d’un RETEX scientifique dans lequel la dimension individuelle de la gestion de crise souhaite être mise en avant, en interrogeant dans quelle mesure les individus participent-ils (ou non) à la gestion de crise (directement et indirectement) et comment ? À partir d’entretiens menés à Saint-Martin auprès des populations sinistrées, l’analyse des comportements et de l’implication des populations face au cyclone Irma a montré une bonne connaissance des phénomènes cycloniques et des consignes associées, ainsi qu’une préparation à traverser l’événement. Toutefois, Irma a dépassé l’aléa de référence (Luis, 1995) pour lequel les populations s’étaient préparées. Les dommages ont révélé et/ou exacerbé des vulnérabilités existantes lesquelles questionnent les processus de reconstruction.
Numerical Modelling of Pipeline Lateral Resistance in Rock Berms
Authors: Thusyanthan Indrasenan , Macaro Giulia , Mesmar Sultan , Guinard Mathieu 
Published: April 2020

Abstract
Rock berms are used for many different offshore pipeline applications such as protection from anchors and trawlers, mitigation against pipeline global buckling and improvement of pipelines on-bottom stability. Understanding the lateral resistance provided by rock berms to pipelines is essential for all the above applications. This paper presents insights into lateral resistance of rock berms restraining pipelines by finite element analyses. Pipelines of various diameters (0.2 m-1.5 m) within typical rock berm geometries were modelled in PLAXIS 2D to evaluate the peak lateral resistance provided by the rock berm to the pipe. The finite element model was validated against available full-scale test data. The results of the numerical analyses demonstrate that the peak lateral resistance of a pipeline in rock berm depends mainly on the unit weight and the frictional properties of the rock, while the mobilization to reach the peak resistance is dependent on the rock berm stiffness. Based on the results from this study, a simplified design chart is presented which provides the lower bound peak lateral resistance for a given pipe diameter under typical rock berm with cover to top of pipe in the range of 0.3 m to 1 m. This design chart could be used by engineers undertaking preliminary design assessment of pipelines in rock berms.
Reliability of Very Large Crude Carrier and Single Anchor Leg Mooring Buoy Mooring System During Squall Event
Authors: Khodr Rabih Ali , Shiban Riyadh Saad , Nawaz Bassim Abdulhadi , Mistry Saleem Parvez 
Published: April 2020

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.
Arctic Subsea Flowline Repair – An Innovative Success
Authors: DeGeer Duane , Paulin Mike , Cowin Todd , Caines Jonathan , Budde Michael , Ullal Varun 
Published: April 2020

Abstract
The Eni Nikaitchuq field development on the North Slope of Alaska consists of the Spy Island Drillsite (SID) artificial island, tied back to shore at the Oliktok Point Pad (OPP) production facility via a 3.6-mile-long buried offshore flowline bundle which contains a 14x18-in pipe-in-pipe (PIP) production flowline. In late 2017, the presence of internal corrosion was detected in the 14-in production flowline, and a repair of the line was performed. This paper presents the work performed to complete the repair, and the engineering and construction challenges overcome by the project team to ensure a timely and reliable repair was executed.
The engineering work was initiated in early 2018 and included initial integrity checks of the 14-in flowline, followed by an evaluation of feasible repair options, and the selection of the preferred repair option, which was to install a 10-in steel linepipe inside of the original 14-in flowline to create a pipe-in-pipe-in-pipe (PIPIP).
The selected repair methodology allowed the total repair project to be undertaken in six months, from the time of repair concept definition to restart of production. Actual production downtime was limited to only seven weeks, with the insertion of the 10-in repair pipe itself taking only ten days. Production has been successfully ongoing since completion of the repair and resumption of operations at Nikaitchuq.
It is believed that this is the first time such a repair has been successfully undertaken, where a steel flowline several miles long has been installed inside of an existing flowline and serves as a good example of how innovative engineering and construction methodologies can be reliably implemented in the Arctic.
Hydrate Blockage Assessment in a Pilot-Scale Subsea Jumper
Authors: Kumar Asheesh , Di Lorenzo Mauricio , Kozielski Karen , Glénat Philippe , F. May Eric , M. Aman Zachary 
Published: April 2020

Abstract
In subsea production operations, wellhead jumpers are one of the subsea facilities more liable to the formation of hydrate blockages during restart operations. To manage hydrate formation and optimize the amount of thermodynamic hydrate inhibitors (e.g. mono-ethylene glycol; MEG) injected, a newly-constructed jumper-like facility (the HyJump flowloop) has been developed in Perth, to simulate shut-down and restart operations over a range of superficial gas velocities.
The test section of the flowloop has a unique geometry to mimic subsea jumpers, with three low points and two high points standing 13′ 2″ tall. The test section is fitted with twelve pressure and temperature sensors spread regularly, a MEG sensor, a valve to simulate the wellhead choke, and a viewing window. In each test, the jumper low points were loaded with aqueous solutions of MEG (0 to 30 wt%) and pressurized with domestic Perth natural gas at a pressure of 1200 psig and pipeline temperature ranging from 41°F to 25.8°F (+5 to -4°C).
The extent of hydrate restrictions or blockages was evaluated through the dynamic pressure drop behavior observed throughout the flowloop. A closer assessment of the pressure drop trace during gas restart suggests that the severity of the hydrate restriction decreases as the MEG content is increased above 10 wt%. Further, our preliminary experimental results illustrate that severe hydrate deposition in the jumper could be completely avoided by injecting MEG at concentrations above 20 wt%. This corresponds to an approximately 50% reduction in MEG content, where ≈38 wt% MEG dosage was required for complete thermodynamic hydrate inhibition at the pressure and temperature conditions used in this trial.
Our unique flowloop facility offers new insight toward hydrate formation in complex subsea jumper-like geometries. Our findings may assist operators in controlling the extent of hydrate formation and deposition in jumper geometries, by optimizing the MEG injection and subsequently supporting lower-CAPEX tieback development concepts.
Innovative Control of the Placement of Concrete Armour Units
Authors: Nicolas Thebaud , Yoann Bugnet , Thierry Mouquet 
Published: April 2020

Abstract
The control of monolayer concrete armour units on coastal protection breakwaters can be time and cost consuming, especially underwater.
Such controls occur frequently on construction projects which last for several years, or during the operation and maintenance of such structures. On top of that, the complexity of this type of projects - usually coastal constructions such a dike easily exceeds 6000 units/km - requires precision and productivity for the control inspections.
As a result, specific control solutions have been developed on the NRL project to inspect the breakwater during its construction.
Improving Mooring Reliability Through Risk Based Monitoring and Inspection
Authors: Wang Suqin Sue 
Published: April 2020

Abstract
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.
Standardization of Additive Manufacturing for Oil and Gas Applications
Authors: Vendra Lakshmi , Malkawi Ameen , Avagliano Aaron 
Published: April 2020

Abstract
As Additive Manufacturing (AM) progresses forward to industrial production, there is a predominant need for standardization to ensure consistency and reliability. Development of industry accepted standards and guidelines is necessary for qualification and certification of AM parts across several industries. AM affords several advantages when compared to conventional manufacturing, including weight reduction, part consolidation, design freedom and inventory reduction, and has demonstrated its potential in industries such as aerospace. Since it is a relatively new manufacturing technology, there is a lack of testing and inspection procedures specific to AM, which hinders the development of standards. Existing testing procedures were developed for traditionally manufactured parts that are not directly applicable to AM processes. A number of Standards Development Organizations are working towards developing guidelines and standards for various processes in the AM value chain. An overview of the current status of Standard Development Organization's activities in the field of AM will be presented, focusing on gaps and industry specific requirements. Specifically for applications in oil and gas, pertinent standards need to be developed to enhance operational and environmental safety, efficiency and sustainability.
The Digital Twin in a Brownfield Environment: How to Manage Dark Data
Authors: Pawlewitz Jan , Mankel Alexander , Jacquin Steven , Basile Natalia 
Published: April 2020

Abstract
This paper addresses the challenges of creating a reliable and accurate as-operated digital twin for a brownfield process plant. Besides massive amounts of information spread over silos, there is so-called "dark data", which is a type of unstructured/untagged data in different formats: 1D (datasheets, lists, records), 2D (drawings, logical connectivity), 3D (physical layout, sizes). This paper describes an approach/solution that makes it possible to validate, connect and make use of this data.
The solution described in this paper was developed collaboratively between Siemens and Bentley Systems. Using a combination of tools and experience from both companies, it is now possible to leverage traditionally inaccessible data to create a single digital twin. The paper will not focus on the solution itself, but rather the process and steps that operators can employ to aggregate, contextualize, validate, and visualize their data so that it can be used to make quicker/more informed decisions.
The solution is an open, cloud-based platform that federates data sources, provides functionalities in the form of microservices, and facilitates the management of the digital twin of the asset, throughout its entire lifecycle. The solution was built as a set of microservices including collaborative process engineering and functional asset information management (i.e., 1D information such as specifications and data sheets and 2D schematics), and 3D design and physical asset modeling. It also contains information management from asset and project management perspectives, including maintenance history, reliability data, and failure mode analyses as well as analytics services and the capability to trace back versions. Many functionalities draw on software that has been used extensively across process industry for many years.
The user is able to use pre-existing 3D plant models or projects authored in most available 3D design tools and mix and match those with models based on photogrammetry or 3D point clouds to create a "reality mesh." The portal accommodates the need for an up-to-date version of accurate asset data, which is critical to making the correct maintenance-related and operational decisions quickly as well as the requirement for historical snapshots (essential to engineering purposes and project progress reviews).
This approach is key in that it enables O&G operators to solve the challenge of creating a digital twin without disruption to the existing physical or virtual environment. Combining 1D, 2D, and 3D in a single environment provides functional context to physical representations and vice versa. The more "dark data" that can be made visible, tagged, validated, and linked to other information, the more valuable and context-rich information will become.
Sensor Ball: An Autonomous Untethered Logging Platform
Authors: Buzi Erjola , Seren Huseyin Rahmi , Deffenbaugh Max , Turner Robert , Ssafwany Ali 
Published: April 2020

Abstract
Downhole conditions of oil and gas reservoirs change with time. Monitoring this change is critical to enhance hydrocarbon recovery from the reservoir. Conventionally, downhole measurements of physical and chemical properties of downhole formation fluids are taken using wireline logging or using permanent downhole sensors. Wireline logging is a complex operation that requires several miles of wireline cable, a winch, a crane and a specialized crew that knows how to operate this equipment [1]. In addition, a blowout preventer, a lubricator and a specialized crew to install and operate are needed. The complexity and cost of wireline operations makes it difficult to acquire reservoir data frequently. The other alternative for gathering downhole data more frequently is installing permanent sensors or optical fibers in the well [2-3]. However, due to the harsh downhole conditions, these sensors need to be extremely reliable and continuously maintained. Moreover, surface data acquisition systems for these sensors increase their cost significantly and reduces their applicability to every well. Both methods have their own limitations and there is a need for more practical and less expensive oil field instruments for well logging. Engineering small, inexpensive and robust logging instruments has its own challenges.
Solving these challenges has been the main focus area of Sensors Development Team at Aramco Research Center in Houston. This paper describes one of the concept ideas that was successfully engineered and tested in our facility and successfully deployed and retrieved in the field in Saudi Arabia in collaboration with our EXPEC ARC and Northern Area Production Engineering and Well Services Divisions in Saudi Arabia.
Benefits of Removing Subsea Control Boundaries
Authors: Kristiansen Karstein Berge , Mæland Sigbjørn 
Published: April 2020

This paper focuses on the benefits of removing existing control boundaries between subsea system components/parts and the automation setup located topsides on the platform (or onshore). The paper describes the communication architecture of existing subsea control systems used today and proposes a new architecture with boundaries removed. This new setup would utilize the same physical (i.e. fiber-optic) communication channels as present systems.
For illustrative purposes, a use case for the proposed system will be presented on an anti-surge setup for a subsea pump/compressor. Existing subsea control systems today are intended for and used to control hydraulic valves in subsea production setups. The design and behavior of these systems make them not optimal for anti-surge control (among other applications). Interfaces and communication protocols used in the proposed use case are based on open industry standards, resulting in a vendor-agnostic system with no proprietary or company-specific solutions, and no boundary between the subsea and topside/onshore located parts.
Potential benefits of the proposed system would include reduced latency, along with the combining of several measured values for increased accuracy over a larger scale, illustrated with an anti-surge example. This could enable operators to realize cost savings through optimization and increased production over the life of the installation. As the paper will describe, the system also has the potential to reduce both CAPEX and OPEX.
Execution of a Megaproject: Delivering the Johan Sverdrup Development Ahead of Schedule and Under Budget
Authors: Thorsen Terje , Bokn Trond , Meling Trond Stokka , Bjarke Therese , Veire Gunnar , Vølstad Janne , Hanssen Ståle 
Published: April 2020

The first phase of the giant Johan Sverdrup project started-up in October 2019, several months ahead of schedule, more than 30% under budget and with a very good safety record. This paper focuses on the execution of phase 1 of this mega-project – from the concept selection and engineering phase, to the global contracting strategy, through the construction across up to 30 building sites globally and until the end of the completions phase offshore Norway – attempting to explain what went well and why, and highlighting potential lessons of relevance to other offshore mega projects on the NCS and globally.
Among other things, the paper looks at the impact of different variables in explaining the improvements made during the execution of the project – market effects, procurement strategies, scope optimization and execution performance. The paper then shows that while market effects played an important role – in part reflecting a project being sanctioned at the beginning of the recent oil and gas downturn – the true driver of the success of the project is found elsewhere.
As phase II of the Johan Sverdrup development is already underway, the paper also looks at efforts made to sustain these drivers of success into the second phase of the project. The paper also describes which parts of the improvement journey that may not be necessarily replicable in the next stage of the megaproject.
Strategies to Advance Offshore EOR Developments
Authors: Poulsen Anette , Jackson Adam C , Dwarakanath Varadarajan , Thach Sophany 
Published: April 2020

Abstract
When setting out to deploy chemical Enhanced Oil Recovery (EOR) solutions in challenging offshore environments, it is important to recognize that unknown uncertainties may exist. These, when identified and characterized through adequate surveillance, can provide valuable learnings. Deployment strategies and chemical solutions therefore need to be flexible and robust under a range of scenarios, some of which will only become apparent once encountered. Many EOR papers have been published on the screening and selection of chemicals for pilots. The work discussed herein applies these solutions to field testing with described strategies. We have developed a process for setting pilot strategies to build on experience and advance chemical deployment for EOR processes (polymer and surfactants). We share lessons learned from some of our offshore tests and present a deployment plan for scale up. The field data collected ranges from short term injectivity tests (spanning days) to large scale multi-well operations (spanning years) that ultimately expand to full field chemical flooding.