bluuebunny/crossref_metadata_2025_split huggingface dataset:
Organisation de la post-catastrophe après Irma à Saint-Martin
Authors: Moatty Annabelle , Grancher Delphine , Virmoux Clément , Cavero Julien 
Published: April 2020

Le 3 septembre 2017 alors que le cyclone Irma s’approche de Saint-Martin, la rentrée scolaire est reportée sine die pour les 8 000 élèves inscrits dans les écoles publiques et les 900 personnels de l’Éducation Nationale. Le cyclone ayant endommagé une majorité de bâtiments et d’infrastructures (dont les établissements scolaires) certains élèves de l’île n’ont pas été scolarisés pendant deux mois. Nous proposons dans ce travail de considérer les récits des adolescents en tant que données susceptibles d’alimenter les retours d’expérience post-catastrophe. Notre objectif est de comprendre le vécu des adolescents et de caractériser les actions qu’ils ont menées en période post-crise. Si leur rôle est reconnu, leurs actions et les contextes de mise en œuvre méritent alors d’être précisés.
Quelles interventions humanitaires internationales pour la reconstruction ?
Authors: Veitl Simon 
Published: April 2020

Suite à une catastrophe, l’assistance internationale se structure selon des normes (cadres d’actions de l’agence des Nations Unies Pour la Réduction des Risques et Catastrophes, UNDRR, et du Global Assessment Report, GAR, de 2015), appliquées par des acteurs (ONU, États et ONG). Les normes cadrent l’organisation de la gouvernance (le cluster), qui définit la trajectoire de « relèvement » et met en place des modalités d’actions. C’est ce système et son impact socio-spatial que nous proposons d’éclairer par un regard critique qualitatif. Pour ce faire, nous avons pris l’exemple de la reconstruction des écoles dans le département du Sud en Haïti après l’ouragan Matthew de 2016. La communauté internationale, via la reconstruction, tente d’y insuffler un nouveau modèle de développement pour la résilience des territoires et de ses habitants. Nous verrons que la réalité résiste à cette injonction d’adaptation.
Managing Risks Associated with Upstream Oil and Gas Field Operations: A Specialized Field Risk Management SFRM Program
Authors: Ballon Alison Cramer , Barrow Robert , Slezak Mark , Laskar Sandipan 
Published: April 2020

Oxy places the highest value on maintaining safe operations that not only seek to protect the health and safety of on-site company personnel and contractors but also strives to prevent potential adverse impacts to the environment, people, and property in the communities where we operate. Achieving our goals requires proactive and effective management of potential business risks and development and implementation of appropriate mitigation actions.
Oxy operates field assets utilized in the production of oil and gas that are located near public receptors. The risk team developed and implements a preventive risk identification and management program to identify, evaluate and manage these risks posed by assets located near public receptors using a consistent method.
This paper describes the overall framework of this program, referred to as a specialized field risk management (SFRM) program, and the processes and methodologies used to evaluate and manage assets located near public receptors. The program first evaluates field assets in comparison with conservative criteria to identify the assets that may have the greatest potential to injure people, harm the environment or damage property should an event occur. Risks are then assessed, mitigation plans developed, and risk mitigation measures implemented. The SFRM program covers topics that include release scenarios, receptor types, impact thresholds, screening methodology, dispersion modelling, and risk mitigation measures.
The SFRM program supports the company's proactive approach towards managing risk and increases company confidence with the assurance of the identification and management of risks associated with assets located near public receptors.
A Novel Approach for Modelling Leakage through Elastomer Seals
Authors: Patel Harshkumar , Salehi Saeed 
Published: April 2020

Abstract
Elastomer is a widely used seal material in oil and gas wells. Seal components in wellhead and completion equipment are important barrier elements for maintaining well integrity. In general, unlike metallic seals, it is believed that elastomer seal's performance is not highly dependent on its surface characteristics. However, there are some evidences that suggest that elastomer surface quality or defects like wear, blistering, etc. can impact fluid penetration risk and leakage.
The effect of elastomer surface quality on sealability is difficult to investigate using macroscopic (equipment level) finite element models. This paper presents a novel modelling approach that can simulate fluid penetration and predict leakage rates considering surface topography/characteristics of the elastomer sealing interface. The leakage model consists of a contact mechanics model and a fluid flow model. Deterministic contact-mechanics model can take surface topographical measurements as an input and simulate actual contact area, and microscopic gaps at different loads. This contact gap information is then used by the fluid flow model to predict flow path and calculate leakage rates.
To represent elastomer seal surface and apply the developed model, different types of rough surfaces were generated. Various operational, design, and failure scenarios were simulated to investigate the effects of surface characteristics, elastomer material properties, fluid properties, etc. on the elastomer sealability. Preliminary results demonstrate that elastomer surface characteristic such as degree of finishing can have notable influence on the seal quality as measured by contact pressure required to achieve zero leakage rate. As expected, harder elastomer seal material exhibited more sensitivity to surface quality than softer material. High fluid pressure and low viscosity were observed to increase the leakage rates for similar contact pressure distribution.
Finite element modelling based seal design is typically limited to the analysis of contact pressure distribution at the sealing interface. Presented leakage model helps further extend the design workflow by enabling consideration of surface characteristics of the seal. With further refinement and experimental validation, the model could be used to create lookup tables of contact pressures. These values can be used as target for finite element analysis of seal equipment design.
Prelude FLNG Driven Anchor Piles in Australian Carbonate Soils: Free-Fall Risk Management by Design
Authors: Dechiron Cyrille , Coste François , Erbrich Carl , Heerkes Marcel , Lange Frank , Frankenmolen Sebastiaan , Van Haaften Ewoud 
Published: April 2020

Abstract
The Prelude FLNG facility anchoring system is based on a turret with 16 anchor legs, each connected to driven anchor piles in generally very weak and variable carbonate soils. Driven piles have a chequered history offshore Australia, due to the very low skin friction that is typically mobilized. At Prelude, the combination of weak soils with some harder layers and low expected skin friction led to numerous installation challenges such as free-fall, overpenetration, soil blow-out and plug depression risks.
Mitigating these risks was achieved in a joint risk-based approach resulting in the unique combination of floating plate parachute, bearing V-shaped cruciform and "pushing" weight tool and installation methodology. Post-treatment of the lifting crane data allowed taking benefit of the experienced soil behavior during the campaign to improve the methods with every pile, leading to the successful installation of the 16 anchors. It also improved the knowledge of the heterogeneous Australian carbonate soils including sand/silt/clay layers through comparison with geotechnical original geotechnical investigations and laboratory tests.
This paper describes the various design and installation challenges and the novel solutions which were applied to manage the substantial risk of failure to install these anchor piles. The successful installation and associated data acquired is unique and have led to invaluable improvements in the understanding of pile-soil interaction in carbonate soils.
The Development of a Machine Learning-Based Image Recognition Tool for Coating Inspections
Authors: Wen Feng , Gu Hai , Wang Bo , Vitali Tyler , Rasberry Hunter 
Published: April 2020

Abstract
Improved remote inspection technologies (such as drones) are enabling safer and more efficient visual inspections of coating conditions in historically hard to reach and dangerous locations on marine and ffshore assets. These technologies may generate a significant amount of data (still images, video) and thus can be challenging for inspectors to identify potential coating failures. This paper presents the development of an Artificial Intelligence (AI) Machine Learning (ML) - based image recognition tool to aid inspectors in the review of data to help make coating condition assessments.
The machine learning algorithm/model development utilizes images taken from different types of maritime assets. These images depict different structural components, coatings, lighting conditions and corrosion. Images were processed and analyzed to create a database for training, validation and testing of the machine-learning model. Multiple machine learning models were developed and then the model with the best performance rate was selected for implementation. Case studies using the tool to process on-site inspection images are presented in this paper. Additionally, a comparison study between the tool performance and human judgment is discussed.
Distribution of the dataset shows that selected images can represent various types of coating failures under different conditions. A recall-oriented metric was selected to evaluate the performance of different machine learning models. Test results of the best performing model show its ability to identify coating failures from field images that have not been previously processed. Comparison studies show the tool can match human accuracy well. These factors support the value of the tool to act as a scanning tool for inspection with remote inspection technologies and as an electronic coating evaluation standard/guideline to aid inspectors.
The study proves the value of using AI technology in the marine and offshore industry. The AI tool supports inspectors with a fast and reliable means to aid them in their decision-making processes during coating assessment tasks, especially when remote inspection technologies are applied. Utilizing more data in the future, the AI tool can be further improved to handle other visual inspection tasks like defect detection, such as cracks and structural deformations.
VXTe Deepwater Tree Development – Cost and Risk Reduction Through New and Advanced Technology
Authors: B Mitchell Andrew , K Norwood Gregory , D Bartlett Chris 
Published: April 2020

Abstract
The oil and gas industry continues to face low energy prices, which has pushed manufacturers to re-think conventional designs and methods that may not be at the efficiency levels required to operate under today’s environmental and economic conditions. This paper describes the development of a new and advanced subsea tree technology that reduces equipment cost and installation time, thereby reducing risk and adding significant value to the end user.
Traditional completion systems have become increasingly complex as efforts were made to address individual problems as they arose. These challenges included wellhead interfaces capable of handling the stack-up tolerances of casing hangers, and a need to orient the tubing hanger relative to a flowline connection system. The solution utilized by most conventional systems was the incorporation of a tubing head spool or some other elaborate means of orienting within the BOP, which created the need for temporary well barriers, required costly workover riser systems and wireline trips, and ultimately led to concentric bore systems with annulus valves located on a tubing head spool.
The VXTe subsea tree system solves the problems associated with wellhead stack-up tolerances and orientation of the tubing hanger, in a simple, robust and elegant manner. The simplicity of the system allows the tubing hanger to be installed like a casing hanger. In this way, the drilling and completion operations may be undertaken without the cost and safety concerns normally associated with temporary well suspensions or BOP trips, and the orientation requirements for flowline connections are completely decoupled from the tubing hanger installation. The requirement for well barriers is also eliminated, thereby trimming the costs of additional spools, and further eliminating leak paths and failure modes. By eliminating the cumbersome solutions employed by conventional systems, our system also eliminates the need for the extensive SIT testing required to validate working interfaces. The VXTe system is a simple, robust and elegant answer to the industry's most pressing subsea tree challenges and aligns with the IOGP requirements agreed upon by most of the major operators.
The VXTe system has undergone a number of verification analysis and validation testing adhering to API standards. In addition to meeting applicable API testing requirements, additional cycle testing was performed to validate the performance of the system over the anticipated life cycle. This included installation and removal cycle testing in addition to pressure and temperature testing. The design details, analysis, and test results will be presented.
Subsea Asset Life Extension in Harsh Environments
Authors: Coupland Benjamin Robert , Avery Mike , Greenaway Robert , Rice Phillip Adam , Weir Douglas 
Published: April 2020

West of Shetland, BP North Sea discovered they had a problem with subsea tree mounted pressure and temperature sensors that whilst dual redundant, still completely failed over time. The measurements are required by the local regulatory body to comply with monitoring of asset integrity and as such once failed the subsea trees were forced to be shut in. Reinstating this production-critical monitoring equipment significantly reduces downtime and deferred production. Later in the life of the field the same damage mechanism that contributed to erosion and fouling of tree mounted sensors had also begun to reduce injectivity within the subsea injection wells and eroded the subsea insert retrievable chokes installed on those trees. BP North Sea initially planned for a campaign of choke insert replacements but later realized the ideal opportunity to incorporate stimulation treatments during the same intervention campaign
The original retrofit package restored an injection well at a cost saving of 70% compared to conventional solutions. However, continued development led to a next generation retrofit package which allowed streamlined configurability to suit a range of choke types across the BP's subsea infrastructure. This enabled life extension whilst introducing enhanced functionality, all whilst optimizing inventory and minimizing capital investment. In parallel, well stimulation operations on 4 water injection wells yielded injectivity improvements of up to 300%, compelling BP to continue to plan further stimulations for future wells. This scenario led to the next generation of retrofit packages including an additional feature of a dedicated hydraulic access point. The access allowing more efficient stimulation operations and providing significant cost saving in terms of vessel time and in-field operations.
The paper discusses the benefits of combining production enhancement technologies and well status monitoring sensors to enable significant improvements in field recovery. Production improvement metrics and lessons learned shall be shared to provide a robust economic justification.
Operational lessons learned from these various activities show how modularity and product streamlining can significantly reduce operating expenditure, time in field, and overall safety of a product.
Collaboration with invested parties can offer additional sources for product improvement which further contributes to product optimization and successful project execution.
Total Experience on Structural Integrity Management of Fixed Steel Offshore Platforms
Authors: Birades Michel , Cholley Jean-Marc , Gillieron Olivier 
Published: April 2020

Abstract
This paper presents the process and methodologies put in place by Total, a major operating company, to manage the structural integrity of its fixed steel offshore platforms located in 12 different affiliates. This paper presents the STIMS (Structural Integrity Management System) which has been put in place to address the integrity of fixed steel offshore platforms. A FUIMS (Floating Units Integrity Management System) is in place for many years to address the integrity of floating units. The STIMS allows in particular the operating company to cope with the recently published third edition of ISO 19900 which requires: "Models used in the analysis and the design/assessment verification of the offshore structure shall be maintained and kept up to date throughout all phases of the structure's life cycle. The operator shall be responsible for ensuring this."
After a description of the fleet of fixed platforms of the operating company (worldwide repartition, age, water depths…), the organization and process put in place between affiliates and Head Quarters, specifically dedicated to fixed steel platforms integrity, are presented. Then some specific methodologies are presented, in particular a new pragmatic approach to define Risk Based subsea inspection plans, which are essential to ensure structural integrity. First, a methodology for inspection prioritization by combining failure consequence, fatigue and inspections results is presented. This method has been implemented for a few decades and identifies the joints most critical to the structural integrity in order to inspect the relevant structural components for ensuring a lifetime extension of a jacket structure. Then, the definition of intervals between inspections is based on a new pragmatic simplified RBI process, called RBI-J. The outcome of the RBI-J analysis is the intermediate and major underwater inspection intervals of offshore structures. It is based on a semi-quantitative approach to estimate the global probability of failure of the platforms due to extreme storms or earthquake. It takes into account the results of the in-place and seismic analyses with some additional semi-quantitative parameters such as robustness, design life, inspection history, cathodic protection, and unprotected appurtenances. The consequences of failure are based on the risk matrix of the operating company, which allows also to estimate the global risk. In line with API RP 2 SIM this risk is then used to define underwater inspection intervals.
The paper concludes with some examples of application of the RBI-J methodology.
The RBI-J methodology is used on the vast majority of the fleet of fixed platforms of the operating company. Full probabilistic analyses are only used on a case by case basis (harsh environment, platforms in poor conditions…).
Additive Manufacturing In The Oil & Gas Industry And Status Update On The New API 20S Standard "Qualification Of Additively Manufactured Metallic Materials For Use In The Petroleum And Natural Gas Industries"
Authors: De Bernardi Carlo , Miller David 
Published: April 2020

The API 20S Standard is designed to play a crucial role in leveraging Additive Manufacturing (AM) to foster innovation in the oil and gas industry. The paper, in association with the standard, will facilitate the understanding of how AM will enable equipment design improvements, faster prototyping, and better inventory management. By way of discussing the progress, challenges, and lessons learned from the standardization process, the paper aims to encourage a safer, broader, and faster adoption of AM technologies in the mainstream oil and gas applications.
The paper will summarize the streamlining process, feedback from the API 20S task group, and current status of the standardization efforts. Additionally, upcoming challenges and the potential for the oil and gas industry industries to contribute to the standard will be summarized. The paper will also showcase a novel tiered approach (Additive Manufacturing Specification Levels) to allow the users of the document to match different levels of criticality.
A Comprehensive Set of Round-Bar Stress Intensity Factor Solutions for ECA of Mooring Shackle and Chain Components
Authors: Aubert Jean-Michel , Dong Pingsha , Sauvage Jean-Pierre 
Published: April 2020

AbstractEngineering 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.
Standardized Offshore Waste Heat Recovery Behind Industrial Gas Turbines
Authors: Saab Richard , van den Bosch Rob 
Published: April 2020

Abstract
This paper focuses on the benefits of utilizing waste heat recovery units (WHRUs) in offshore oil and gas applications. Today, a high number of offshore installations use gas turbines (GTs) for power generation and as mechanical drivers for critical equipment, such as compressors. Most installations, however, do not employ any form of waste heat recovery. This results in wasted energy and increased emissions, as hot exhaust gases from the GT are vented to the atmosphere.
One of the factors that has contributed to the limited use of WHRUs on offshore facilities has to do with weight and space limitations. The paper discusses how original equipment manufacturers (OEMs) are addressing that challenge through both design standardization and modularization. For illustrative purposes, the paper discusses a line of standardized WHRUs which are designed for industrial and aeroderivative gas turbines in the 10–70 megawatt (MW) range. The WHRUs can be used for thermal fluids or applied as a drum-type steam generator (DTSG) or once-through steam generator (OTSG). Their vertical compact layout makes them particularly well suited for offshore installations, such as floating, production, storage, and offloading (FPSO) vessels, where weight and footprint of topsides modules are of particular importance.
By standardizing the WHRU/DTSG/OTSG and leveraging a high degree of modularization, the units can be easily modified per project. Construction time can also be reduced by up to ~ 70% when compared to traditional horizontal gas turbine heat recovery designs. Standardization also enables a reduction in engineering efforts during project execution – resulting in increased product quality and lower CAPEX.