bluuebunny/crossref_metadata_2025_split huggingface dataset:
LINKING CONSTRUCTIVE AND ENERGY INNOVATIONS FOR A NET ZERO-ENERGY BUILDING
Authors: Pujadas-Gispert E. , Korevaar C.C. , Alsailani M. , Moonen S.P.G. 
Published: April 2020

INTRODUCTION
This article explains the design, construction and energy strategies of LINQ, a netzero energy building that was successfully entered into the Solar Decathlon Middle East 2018 held in Dubai. Students of engineering, building physics, architecture and urban planning designed, built and operated LINQ. It is mainly powered by solar energy and made of bio-materials. Some of LINQ's innovations are the ventilated façade with customizable bio-based tiles, the indirect evaporative water cooling system, and the light building integrated photovoltaic-thermal system. LINQ sent more energy to the grid than it drew throughout the competition. However, energy production could have been improved according to simulations and technical specifications. LINQ is a good example of current and future building expectations—combining multiple criteria, strategies, and solutions—to contribute to environmental, social and economic sustainability.
MOHAWK COLLEGE'S NET ZERO ENERGY AND ZERO CARBON BUILDING—A LIVING LAB FOR HIGH EFFICIENCY AND RENEWABLE ENERGY TECHNOLOGIES IN BUILDINGS
Authors: Bhavsar Rutul , Cupido Anthony , Arriaga Mariano 
Published: April 2020

INTRODUCTION
In recent years, large high efficiency and Net-Zero Energy Buildings (NZEB) are becoming a reality that are setting construction and energy benchmarks for the industry. As part of this significant effort, in 2018, Mohawk College opened the 8,981 m2 (96,670 ft2) Joyce Centre for Partnership and Innovation (JCPI) building in Hamilton, Ontario; becoming Canada's largest NZEB and zero-carbon institutional facility. The building integrated a high-efficiency design, construction materials, and technologies; as well as renewable energy technologies to significantly reduce its annual energy consumption and greenhouse gas emissions. Furthermore, the JCPI building was also designed as a living lab where students, faculty, researchers and industry are able to monitor and validate the performance of this state-of-the-art facility. The building was designed to have an energy use intensity of 73 kWh/m2·year (0.26 GJ/m2·year); hence, potentially consuming approximately 80% less energy than the average educational service building in Ontario. This paper gives an overview of the design criteria and technologies that were considered to achieve this innovative building.
Apports de l’imagerie satellite pour le suivi de l’impact des événements cycloniques à Madagascar
Authors: Catry Thibault , Révillion Christophe , Mouquet Pascal , Pennober Gwenaëlle 
Published: April 2020

Cette étude porte sur l’utilisation de l’imagerie satellite pour le suivi des cyclones et la caractérisation de leur impact. Deux événements récents sont étudiés à Madagascar : (i) Le cyclone Haruna, impactant la côte sud-ouest en février 2013, (ii) Le cyclone Enawo, touchant la côte nord-est en mars 2017. Le suivi de ces deux épisodes a montré la faisabilité de la mobilisation de l’imagerie satellitaire sur Madagascar pour une quantification des surfaces inondées associées aux cyclones. La combinaison des capteurs optiques et SAR (Synthetic Aperture Radar) à haute résolution temporelle et spatiale (HRS) abouti à : (i) un suivi en quasi temps réel d’Haruna par une surveillance des inondations pendant la crise et de la décrue en post-crise (ii) une cartographie des inondations en zone urbaine et dans les rizières de la région de Maroantsetra et Sambava, associées à Enawo, en combinant des images Sentinel-1 et 2, Pléiades et une démarche de cartographie participative.
Johan Sverdrup: The Digital Flagship
Authors: Larsen Paal Frode , Tønnessen Tor , Schuchert Florian , Khamassi Ahmed , Jarraya Haithem , Aarrestad Henriette Dorthea , Imsland Vegard , Lossius Vibeke 
Published: April 2020

The sheer size of the 2.7-billion-barrel field and expected operations of more than 50 years, make Johan Sverdrup an exciting place to develop the solutions of the future. As such, the Johan Sverdrup field development has been called the digital flagship for the operator. Being a ‘flagship’ means Johan Sverdrup is not only meant to be a vehicle for digital innovation to improve safety, value-creation and carbon efficiency for the field itself, but the field development is also meant to drive digital solutions and ways of working that have the potential to be scaled-up for the benefit of the operator as a whole.
This paper starts by setting out the main digital focus areas for the Johan Sverdrup development, but drills down on exploring the areas where Johan Sverdrup is demonstrating real and tangible impacts already today. Examples include efforts to mature technology for automatic production optimization, a number of new pipe and seabed technology solutions (including fiber-optic PRM, fiber-optic monitoring of wells), and the step-wise development of a digital twin for Johan Sverdrup that will gives the opportunity to model and visualize key parts of the field.
The paper describes the ‘digital field-worker’ at Johan Sverdrup which is changing the way of working, both during the construction and completion phase, but also during operations. This ranges from efforts to automate and digitalize work processes offshore to more innovative solutions. Examples of the latter include Echo – a multi-player digital twin solution allowing real-time visualization and collaboration between onshore and offshore – as well as the iterative development of anomaly detection models (utilizing machine learning and artificial intelligence) to move from condition-based monitoring towards predictive maintenance.
HPHT Subsea Production Tree – A Unique Approach to 20KSI 350F In-The-Wellhead Completions
Authors: Morse Justin Edward , Tse Kearn Che , Wilson Stuart - , Mayer Christopher Campbell , Kaculi Jim T. 
Published: April 2020

AbstractDemand for subsea production equipment capable of withstanding high-pressure/high-temperature (HPHT) operating conditions is increasing as the subsea industry progresses into new frontiers. Various subsea Original Equipment Manufacturers (OEMs) are striving to develop and qualify economically viable subsea trees (XTs) to meet this demand and the industry is beginning to see some of the first subsea HPHT greenfield developments move forward. This demonstrates that the economics of these projects are starting to meet investment thresholds. However, there remains ample opportunity for new designs and system configurations to increase operating profits and reduce the economic risk for operators drilling and completing these HPHT subsea wells.This paper presents one approach to 20 ksi HPHT subsea developments which delivers on both objectives. The unique manner of accomplishing lower costs and reducing risk involves a system capable of 20 ksi completion in the wellhead (WH), thus eliminating the tubing head (THD). This system is currently under development and qualification per API 6A, 17D, and TR8 requirements. This paper provides an overview of the system configuration, a description of the ongoing verification, validation, I3P and regulatory review process, and a state-of-the-art HPHT R&D Centre where this effort is being undertaken.
BC10 New Oil Enabled by Deployment of New Technologies
Authors: Tonin Bruno , Labes Alan , Wang Wensen , Pereira Leury , Duarte Carlos , Vianna Gustavo , Zylberman Michael 
Published: April 2020

The BC10 block encompasses multiple deepwater fields offshore Brazil and is tied-back to the FPSO ´Espirito Santo´. Since achieving first oil in 2009, the production was expanded through the Phase 2 and Phase 3 subsea tie-backs, having by early 2019 a total of 29 wells connected to the system. BC10 is a joint venture among Shell (operator), ONGC and Qatar Petroleum.
As part of the strategy of "filling the hub", the development team matured infill well opportunities, which materialized in New Oil throughout 2019. The delivery of this additional production was enabled by the deployment of various new technologies, which supported the accelerated schedule and low-cost mindset of the project. Most notable is the deployment of the Compact Manifold and jumpers with flexible lines integrated to the horizontal connectors.
In parallel to new wells, the Subsea team worked on a system debottlenecking that enabled the production of additional 2,000 bpd by routing selected fields to dedicated subsea pumps, instead of commingling low- and high-pressure systems into same inlet pressure pumps. This was enabled by installation of an electrical actuator that automated control of a formally manual valve at low CAPEX.
Looking forward, the BC10 Infills Project team is planning for Q1 2020 the installation of the next-generation of Xmas Trees. This Xmas Tree is significantly lighter and cheaper than the previous company standards Enhanced Vertical Deepwater Tree(EVDT). It required significant qualification effort from R&D to ensure all new components delivered as part of this new generation of XT are reliable and satisfy the systems functional requirements. The qualification is completed, it has been confirmed that the well OS2 will carry the first new technology Xmas Tree in 2020.
Subsea Field Development Schemes Integrating Subsea Chemical Storage and Injection Systems: Benefits and Challenges for Long Tiebacks
Authors: Di Felice Annalisa , Filippi Alessandro , Arcangeletti Giorgio , Aloigi Elvira , D’Amico Amerigo , Radicioni Alessandro 
Published: April 2020

Abstract
Chemical injection in subsea fields is a consolidated practice to solve or prevent flow assurance issues that may occur linked to hydraulic, thermal and operability requirements, especially in transient conditions.
The traditional approach adopted to supply chemicals to a subsea tieback is to position the chemical injection system, including pumps and storage, on the platform/FPSO, transporting the chemicals subsea through the umbilical or the chemical lines in case of high flow rates, and performing chemical distribution subsea up to the injection points.
In the development of a long subsea tieback, costs for the umbilical system tend to increase based on its length and complexity. Moreover, pressure drops and control of chemical delivery pressures and flowrates through such a long umbilical can be extremely challenging, together with the risk of umbilical line blockages and their related issues.
The design resolution to enlarge the diameter of the chemical conduits in umbilicals leads to an increase in unit weights and, combined with the umbilical length, additional costs and packing and installation challenges.
These factors drive the need to review the conventional chemical injection system architecture and to make the development of a long tieback sustainable from the point of view of cost and technology.
To overcome these major criticalities, the chemical injection system can be placed subsea, possibly close to the injection points.
Recently, Saipem has mapped the typical chemical demand for a representative size oil fields, with the main aim of defining a subsea chemical injection system architecture and its related main components.
The main result of this exercise is the definition of a configurable architecture for subsea chemical storage, injection and refilling facilities to be located close to the subsea users, based on operating consideration suitable for offshore and deepwater scenarios.
A "building block" approach is followed together with a certain degree of equipment standardization, where possible, allowing for a flexible system that can be adapted and tailored to the specific field. Technology development status has been also considered and specific Saipem technologies, currently under qualification or being patented, have been considered and integrated in the concept.
Best Practices for Using Coiled Tubing to Assist Plug-And-Perf Multistage Fracturing Operations in HP/HT Wells
Authors: Singh Ishaan , Saraf Aman , Pathak Akash Ramesh , Bandyopadhyay Bholanath , Dehingia Madhurjya , Wijoseno Danny Aryo , Shaik Moulali , Rao Dasari Papa 
Published: April 2020

Abstract
The plug-and-perf (PnP) method is widely used globally for multistage fracturing operations. With only a few jobs performed worldwide, coiled tubing (CT) assisted PnP operations in high-pressure/high-temperature (HP/HT) wells are largely uncharted and most challenging. The "A" field in India has HP/HT formations, with bottomhole temperature (BHT) of 310°F and reservoir pressure of 9,000 psi. Whereas the PnP method is widely used globally, there are few examples in wells with completion restrictions or whose downhole conditions dramatically increase depth inaccuracies and equipment damage. This study describes how to address challenges such as depth correlation (which affects plug-setting depth accuracy), low injectivity, completion restrictions, and heavy brines (which damage CT). To gain further understanding of operations, simulations are sensitized to identify solutions for pumping rates, HP/HT conditions, well kill fluid, milling, and cleanouts where obstructions hindered BHA penetration.
The proposed best practices presented here are for primary CT operations involved in the complete PnP cycle, such as wellbore displacement, well dummy run-drift, setting the isolation plug and milling, acidizing using jetting tools, sand cleanout using gels having best performance in HP/HT environment and motor-mill runs with durable resistance in harsh environment, well kill (using 13.65-ppg calcium bromide), and nitrogen lift. The featured case studies describe operations including seven bridge plugs being set at accurate depths and milled after fracturing; cleanout of a 340-m sand column is also featured, as well as well kills with heavy brines. Optimized operational parameters such as CT speed, pumping rates, and the use of smaller outer diameter bottomhole assemblies doubled operational efficiency during those operations.
Discovering Connectivity Between Different Sand Units in a Field With Multi Stacked Reservoirs After Nearly Two Decades of Production – A Case Study
Authors: Jamaludin Izzuddin , Basri A Hakim , Mohd Nor Saiful Azam , Arsanti Dian , Dzulkifli Izyan Nadirah , Mohd Azkah Mohd Zubair 
Published: April 2020

Abstract
Field A is located offshore of Peninsular Malaysia, consists of multi stacked reservoirs where previously the vertical communication between different units was considered to be well understood. Separate reservoir models were built independently where fair to good history matching were achieved during the dynamic modelling study. Subsequently two drilling campaigns were executed based on the simulation results. On top of that, regular reservoir surveillance and frequent simulation model updates have assisted in assessing vertical connectivity.
North of Field A, a recent drilling campaign in early 2019 indicated possible communication between infill wells in Unit 35U and water injectors in Unit 35L. One of the well is experiencing severe watercut production than initially forecasted. It is well understood that the seismic amplitude for Unit 35L is being overlapped by the stronger response of Unit 35U in the northern area. Due to that, the reservoir modelling and understanding for Unit 35L in this region is mainly driven by actual well controls and the geological model, rather than from seismic.
Meanwhile in the Southern area, a stable reservoir pressure trend is observed in Unit 27 despite reduction of cumulative voidage replacement ratio (VRR) from 0.6 to 0.4. Additionally well C02ST1 was producing oil at an increasing rate, a trend which the current reservoir model failed to match. The model also failed to explain the unreasonably high recovery factor (RF) of 50% for Unit 27 given the delayed water injection and small gas cap support.
Back to the North, well interference testing was conducted by shutting in water injectors in Unit 35L and observing the pressure response of a new well in Unit 35U using a permanent downhole gauge (PDG). Observations indicated a decrease in pressure response once injection was turned off, confirming the communication between the two units. Moving forward, two injectors for Unit 35L will be temporarily suspended to relax the watercut trend in the new wells, thus improving the oil rate.
In the South, a material balance study and reservoir 3D model suggest additional volume needs to be introduced for Unit 27, which indicates that it is probably draining Unit 35U oil due to a higher level of vertical communication and overlapping sand bodies between both units. This is also supported by produced water salinity readings of well C02ST1 (Unit 27) having similar values as Unit 35U wells rather than other Unit 27 wells.
Communication between different layers often requires longer time and a significant amount of production to be well established and observed. This case study proves that reservoir understanding can still be a mystery even when the field is reaching 20 years of production.
A Carbon Footprint Evaluation Method for Offshore Floating Wind Installations
Authors: Istad Tonje , Kopsov Igor , Bernardini Valeria 
Published: April 2020

Abstract
Carbon footprint is becoming increasingly important on the business agenda. For a floating wind project dedicated to providing clean energy, an engineering study was performed to present a case and gain additional knowledge on how to develop a green execution model related to the wind turbine substructure and mooring system.
Emission calculations, sensitivity analysis, sourcing strategy development, material usage and transportation assessment were used to quantify the environmental benefits and carbon reduction of the various combinations and scenarios. The carbon footprint calculations and project execution method presented in this paper can be a reference for sustainable practices in future floating or conventional wind energy projects.
The study showed that floating concrete substructure carbon footprint may be considered lower than a floating steel substructure. The mooring system, which is the same for both types of substructures, accounted for a significant portion of the carbon emissions.
Logistics accounts for a large share of emissions: How and where goods are procured and transported are as important as the material selected. Locally fabricated items made from greener certified materials are preferred. Use of environmentally friendly concrete in substructure fabrication and suction anchors in glass reinforced plastic (GRP) are two typical examples of more sustainable approaches.
Floating wind in combination with a green project execution model is a relatively new concept. Performance of the study showed that internal communication and promotion of carbon footprint awareness are essential for the project team's success. Emissions may deviate from what is initially anticipated. Moreover, it is vital to apply a green execution model to the establishment of cross-company communication and a focused task force. To ensure engagement from team members and reduce bureaucracy, positive reporting of carbon reduction considerations during project execution is recommended. This emphasizes the psychology of a team buy-in based on positive experiences and rewards for considering climate considerations.
State of Technology: Cleaning and Coating UAV Systems - Industrial Spray Painting Drones
Authors: Dahlstrom Robert L. 
Published: April 2020

Abstract
Cleaning, applying and testing coatings on corrosion-susceptible surfaces, such as those in Oil & Gas and extreme environments such as offshore Oil & Gas assets, currently requires extensive manual labor. Further, cleaning, coating and measuring coatings at height can create a dangerous occupational environment. Drones, also known as unmanned aerial systems (UAS), unmanned aerial vehicles (UAV), or small unmanned aerial vehicles (sUAV) can be leveraged to perform some of these tasks, including cleaning, coating, and inspection while keeping workers safely on the ground. Of note are some current aerial robotic inspection platforms in the market that make physical contact with structures for nondestructive testing (NDT) in addition to visual inspection.
Drone capabilities have significantly evolved over the past decade, and it is expected that the ubiquity of such systems will continue to increase in the years to come. While no coating or cleaning drone is commercially available at the time of this publication, one company has an existing prototype currently under development as part of a Joint Development Agreement with a large international coatings manufacturer for industrial application that is expected to be tested in industrial environments this year. This prototype is a custom-manufactured drone with a tether to the aircraft from the ground that delivers power and cleaning or coating material. An on-board computer manages flight navigation along with intelligent spraying. While the utilization of this new technology faces many challenges, it is important to recognize the potential and projected growth in use of such systems. An introduction to the current state of coating and cleaning drones will be discussed, along with limitations and benefits the system can provide to the coatings and corrosion control in the Oil & Gas industry.
Use of Membranes for Gas Processing at Offshore – A Case Study
Authors: Gupta Anil Kumar , Verma Abhijeet , Sukanandan J N , Kakkar Rajesh 
Published: April 2020

Abstract
The case study applies to an Indian offshore production field which consists of 4 unmanned well head platforms (A1, A2, A3 and AB) and a chartered hired FPSO connected via PLEM to the hub platform AB. The producing wells use gas lift supplied from gas compressors located on the FPSO. Liquid produced is evacuated by tankers and excess gas is exported to an adjacent field via a 16" × 46 km pipeline. New discoveries with total oil in-place volume of 75.55 MMt and associated gas with greater than 30% CO2 have posed a challenge to bring into production. The gas compressors on the FPSO were designed to for gas with maximum 12% of CO2 and as the FPSO is a leased asset, the increased CO2 in the feed was considered "a strict no-no". Also, excess gas is exported via and must have less than 6% CO2 to meet the export pipeline specification.
A concept study was done to identify a feasible method to produce the higher CO2 gas without major changes in FPSO handling facilities. In the technology selection: Solvent adsorption, Absorption beds and Membrane system were evaluated for their usage at an unmanned platform. The selection criteria included: required foot-print & weight, moving parts and minimum intervention. The study recommended a membrane system be used.
This project has many firsts for Offshore India such as: Membrane based CO2 removal, a low BTU hot flare for reject stream disposal and Micro-turbines for meeting basic power requirement. All this will be discussed with fabrication pictures and implementation details. Scheduled offshore platform commissioning is in January 2021.