bluuebunny/crossref_metadata_2025_split huggingface dataset:
Iceberg Towing in Ice Conditions
Authors: Efimov Yaroslav Olegovich , Kornishin Konstantin Alexandrovich , Buzin Igor Vladimirovich , Gudoshnikov Yuri Petrovich , Nesterov Alexandre Valerievich , May Ruslan Igorevich , Sochnev Oleg Yakovlevich , Tarasov Petr Alexandrovich 
Published: April 2020

AbstractThis paper presents field results and analysis of iceberg towing experiments performed in the Barents and Kara Sea in 2016-2017. For the first time ever in the industry, this research was based on a complex study of the icebergs origin and properties. For that purpose prior to the trials outlet glaciers of Novaya Zemlya, Franz Josef Land and Severnaya Zemlya were examined with airborne radar that allowed to measure their thickness and to build 3D models. Satellite remote sensing data were used to derive glacier fronts position, ice surface flow velocity, changes of glacier margins, and parameters of iceberg distribution. The data on the flow rates of the main glaciers were compared with the satellite beacons equipped with GPS (ARGOS) installed on several glaciers. Empirical relationships were derived to determine the mass and geometry of icebergs based on instrumental measurements and airborne data in the Barents and Kara seas. All this information was used to estimate iceberg towing possibilities in different conditions, analyze obtained data and deeper understand the process. Influence of oscillations during the towing process was studied. For a wide range of towing speeds, drag force coefficients were determined for icebergs of various sizes and shapes. Experimental iceberg towing operations performed in ice fields during the early stages of ice formation are described. These works were conducted in October 2017 in the Kara sea. Limitations of iceberg towing under different ice conditions are determined and discussed. Technological features of towing operations within negative air temperatures and the presence of sea ice are also highlighted.
Development of Detailed Reeling Analysis for Electrically Heat Traced Flowline EHTF System
Authors: Rajaratnam Sabesan , Bedrossian Arek , Roy Alan , Lacerda Narciso , Cherkaoui Saad , Giraudbit Sonia , Gitahy Leonardo 
Published: April 2020

AbstractThe Electrically Heat Traced Flowline (EHTF) is characterised by a combination of high performance dry annular thermal insulation of Pipe-in-Pipe (PiP) with a restricted electrical heating capability provided by helically wound copper wires laid between the inner pipe and the insulation in the annulus. The main advantage of EHTF are: future tie-back integration, unlock marginal reserves, access to HPHT pipeline, extend field life and maximise economic recovery and reduction in chemical and energy usage operational flexibility in controlling the flowline temperature and preventing the formation of wax and hydrates in shutdown conditions. Fibre optic cables are deployed in the EHTF system to measure the temperature of the flowline.This paper presents the development of a detailed finite element model to predict the mechanical behaviour of the helically wound cabling during reeling operations. The wires and cables were represented explicitly in the model as initially straight and then wound helically around the inner pipe with specified pre-tension. The EHTF PiP system was then cyclically deformed against a former to simulate the reeling process. A fibre optic cable (FOC) containing a local imperfection due to denting was included in the model to assess the impact of reeling process on the continued acceptability of accidentally dented FOC.The effects of friction between the cabling and the inner pipe and insulation surfaces, the pre-tensioned helical winding process and helix pitch, and the restraint provided by the thermal insulation layer and centralizers, were all investigated. Physical tests were conducted to establish the cyclic material properties of the electrical wires and results from these tests were used to calibrate the FE model.This paper details Subsea 7's technical expertise in modelling the highly complex behaviour of the EHTF cabling system as it experiences multiple bending cycles due to reeling. The paper highlights some important key results describing the behaviour of the wires and consequent predictions of integrity which have since been verified through full scale physical tests. The FE modelling also contributed to the insight gained regarding the overall behaviour of the system.
Underwater Intervention Drone Subsea Control System
Authors: Abicht Daniel , Torvestad Jan Christian , Solheimsnes Pål Atle , Stenevik Karl Atle 
Published: April 2020

Abstract
To support the digitalization trend in the industry, a higher degree of automation is required. Equinor has launched an Underwater Intervention Drone (UID) initiative backing this trend and paving the way for new, flexible and cost-efficient operation and maintenance philosophies. To cater for this technology the subsea control system infrastructure must be prepared for.
The target of the UID initiative is to develop concepts and solutions to establish cost effective technologies equally striving for standardisation of products and interfaces. The UID initiative aims to have a system approach and examine the impact on all elements of a subsea development, i.e. covering topside, umbilical, SPS, docking station and drone. This will safeguard the benefits during technology implementation and operation. As part of that, the UID control system needs to be designed under consideration of aspects such as safety, application, robustness, simplicity, standardization, cost of ownership and project execution philosophy.
While most of the main technology elements are available and proven in use there is a great potential for interface standardization by introduction of new equipment such as the Subsea Docking Station (SDS). New interfaces between well-established subsea disciplines such as subsea control and distribution, subsea production, and intervention systems will have to be handled to ensure seamless integration. This provides the possibility of open-standard solutions ensuring interoperability and interchangeability from day one.
With focus on UID control system infrastructure, this paper will present the current status of the UID initiative with focus on the UID subsea control system covering: the fundamental features of the UID control system technology and conceptthe consequences of UID technology for the design of production control systemsstatus of the UID subsea control system initiative with respect to technology maturitythe activities required to close the identified technical gapsthe implementation strategy
The Spar Platform – Transforming Deepwater Development
Authors: Sablok Anil Kumar , Weaver Tim Otis , Halkyard John Edwin 
Published: April 2020

Abstract
This paper reviews the evolution of spar designs, focusing on the progression of work that ultimately lead to the application of this new concept to the oil industry. This papers updates and expands on a previous paper by one of the co-authors. This paper discusses the evolution of spar designs from "classic" deep draft caisson designs to the truss spar and the cell spar. The paper discusses the reasons the spar was successful in the first place, and how its design has been tailored to varying field development requirements over the years. It discusses specific considerations in supporting risers from spars, and the unique motion characteristics in waves and currents. The simplicity of the early spar hulls is discussed. Finally, the role of key players especially the inventor Ed Horton that helped make the history of the spar a successful one is discussed.
The spar is the only successful dry tree solution for deep water production that can successfully operate in the deepest fields today and in the most severe environments. Its deep draft results in natural periods outside the range of waves, which has led to its wide acceptance for different field scenarios. The largest disadvantage of the spar is arguably the logistics of deck installation, which normally requires an offshore heavy lift. The paper discusses the research that was done on heavy topsides floatover for the spar, and the successful floatover operations both offshore and inshore.
The paper provides a unique look at the history and evolution of this concept showing how the idea originated and how the design was improved and adapted as data on its performance became available and new requirements emerged.
Integrated Production System Modelling and Optimization for Advanced EOR Application in Pre-Salt Offshore Carbonate Reservoir
Authors: Hamedi Shokrlu Yousef , Pathak Varun , Kumar Anjani , Salazar Victor 
Published: April 2020

Abstract

Objective/Scope
Applicability of Enhanced Oil Recovery (EOR) processes is gaining interest among offshore operators in recent years. CO2/miscible gas injection and Water Alternating Gas injection (WAG) are the most attractive EOR methods being considered by most offshore operators. Due to limitations imposed by the surface facility, any process optimization done through standalone reservoir simulation could be unreliable as the facility constraints and its effects are neglected. In order to minimize risk and reduce uncertainty, successful modelling and optimization of such projects requires integration of subsurface modelling with surface facility model.
In this work, field development and optimization of a complex offshore production system, from a Pre-Salt carbonate reservoir offshore of Brazil is studied. Different field development scenarios, including water flooding, miscible gas injection, and WAG injection, are considered. Compositional fluid model is used in order to correctly model the fluid mixing effects and miscibility. Pressure change and thermal effects are considered in all the facility equipment. The complexities of the surface network, including gas sweetening, compression, and fluid blending are included in the integrated model.
A new multi-user, multi-disciplinary Integrated Production System Modelling (IPSM) tool is used to fully-implicitly couple reservoir simulation with surface facility model. Production from the offshore asset is optimized for different development scenarios. The provided IPSM approach optimized operational schemes that were consistent with the constraints of the offshore facility. Additionally, with this new approach, all users from different disciplines were able to collaborate seamlessly, and any possible inconsistencies and discontinuities that could occur due to use of multiple decision making tools were removed.
The use of integrated production systems modelling for optimizing EOR schemes in offshore assets, particularly miscible WAG, is proved to provide more robust answers. The complexities and Uncertainties of such processes, for both reservoir and facility models, are successfully studied.
Floating Offshore Windfarm Integrated in the Subsea Field Development - Saipem Windstream Concept, Applied to a Case Study
Authors: Mauries Benjamin , Arcangeletti Giorgio , Colmard Christophe , Di Felice Annalisa , Delahaye Thierry , La Sorda Enrico , D'Amico Amerigo , Temeng Kofi-George 
Published: April 2020

Abstract
Oil and Gas Operators are moving active production and injection equipment onto the seabed with the aim of reducing CAPEX and/or topside space requirements. Moreover, they want to minimize new production floating facilities (e.g. through tie-back to existing FPSO/Floaters).
Given this scenario, the overall electric power needs may become an issue because of the extra power demand due to the increasing number of electric consumers placed subsea. These electric loads may include the subsea boosting (pumps or compressors) operations, pipeline heating or the typical subsea water, chemical injection and valves actuation (in the case of all electric control systems), just to mention some of potential subsea power consumers, and may exceed the existing FPSO/Floater power production capacity. A potential solution to overcome this issue consists of the deployment of wind generators combined with topside Island power generation.
Offshore wind power is indeed more and more considered for shore power supply, but also by the Oil and Gas industry with the objective of reducing the carbon footprint of their facilities. High power marine wind generators are already consolidated technologies for near coast, and today they are evolving in the short-term to floating solutions for the open sea.
Saipem has developed its own floating wind turbine solution, called Hexafloat, consisting in a pendular floating foundation made of tubular elements and connected through tendons to a counterweight. This solution is particularly cost-competitive for deepwater locations (thanks to the low mooring costs) even for harsh environmental conditions (thanks to an excellent stability), and will unlock the possibility to deploy large wind power generators far from the coastline in deep water.
The system composed by the Hexafloat base and the wind generator may be equipped with onboard back-up generation utilities to provide continuous power supply for subsea, despite wind intermittency, and to provide support to certain subsea field development services, making the assembly a kind of supporting device for the subsea field or for the FPSO.
This is the Windstream concept that is under internal development and that will be better described in the present paper through the explanation of the results achieved within a couple of case-studies analyzed.
Real-Time Composition Measurement for Fiscal, Allocation and Process Optimization
Authors: Potten Gary M , Wright Stuart F , Moreau Jon F A 
Published: April 2020

Abstract
The global oil industry has a large installed base of mature offshore platforms and facilities, often with declining production. A trend is to use this infrastructure to produce and process new discoveries, reducing time to production and recovery costs while extending infrastructure operating life.
However, production of new oil fields using existing infrastructure presents unique technical challenges. Accurate, repeatable and reliable measurement of produced oil and water is vital for fiscal, allocation or royalty purposes, as well as automation and control. This challenging measurement requires high-energy mixing with low power consumption and negligible pressure loss in a very small footprint.
The measurement uncertainty of net oil (oil minus water) for fiscal and allocation purposes is defined by international standards and contracts. With the increase in the use of declining facilities, a new technical challenge has emerged. To be able to accurately allocate the new fluids to the field, partner or different tax regimes they must be measured to fiscal accuracy prior to being mingled with other fluids for processing. Oil and water measurements are often performed at the output of first stage separation. This creates a challenge, as the fluids are close to the critical pressure, meaning that any pressure drop potentially results in cavitation. In addition, production pipelines are generally less than 8 inches, so any obstruction causes an undesired pressure loss or restriction.
These requirements highlighted the need for an effective, nonintrusive mixing device to enable operators to accurately measure and control the new fields being developed with today's greater capital constraints. Research was conducted, as part of a Joint Industry Project, at Imperial College in London followed by extensive computation fluid dynamics modeling to develop a conceptual design. The design was independently tested at the National Engineering Laboratory at East Kilbride, UK. The test independently verified that the design met the uncertainty performance criteria of the international API and ISO sampling standards across the wide range of water cut seen in both mature and new production. Once verified, the design was scaled for operating line sizes seen in the targeted application, and early deployment sites were identified.
The paper discusses the application envelope identified by offshore operators and the technical challenges they were seeking to solve. It follows the design process, highlighting the choices made and the results and methodology used in the independent testing to verify performance.
Johan Sverdrup: Lessons-Learned from the Field-Development of a North Sea Giant
Authors: Meling Trond Stokka , Bjarke Therese , Veire Gunnar , Bokn Trond , Thorsen Terje 
Published: April 2020

In the same year that the Norwegian Continental Shelf (NCS) celebrates 50-years since the Ekofisk discovery in 1969, which in earnest established Norway as an oil and gas nation, the start-up of the Johan Sverdrup development will extend profitable oil and gas production with lower carbon emissions from the NCS for another five decades.
The third largest oil field on the NCS, after the Ekofisk and Statfjord fields, and with recoverable reserves estimated at 2.7 billion barrels of oil equivalent, Johan Sverdrup certainly has the resources to be a North Sea giant. However, being a giant is more than having the necessary resources in place, it is also about turning these resources into recoverable reserves that can be produced in a safe, profitable and – increasingly in today's context – carbon efficient way.
This paper provides a high-level summary of the experiences and lessons-learned from the development of the Johan Sverdrup field, and has the objective of serving as an introduction to the technical session papers that follow. As such, the paper aims to highlight what it took to make Johan Sverdrup a true North Sea giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. The Johan Sverdrup development has set a new standard for project execution in Equinor, the paper concludes with lessons-learned of relevance for both Equinor's future project portfolio and projects globally.
Subsea High Voltage Substations for Floating Offshore Wind Applications
Authors: Eidsvik Håkon , Bekhouche Christophe 
Published: April 2020

Abstract
Over the last few years, the oil and gas industry has been challenged by prolonged volatile hydrocarbon prices and market instability. As a direct consequence of these challenging conditions, the industry has experienced a shift of focus to the development and application of more advanced and efficient technologies.
One of the most revolutionary subsea technological developments implemented in the latest years has been the subsea compression system installed at the Åsgard field, located offshore Norway. It has successfully been in continuous operation since September 2015. This has proven the feasibility of installing a compressor on the seabed, and at the same time verified a large number of power and control system technologies required for the control and operation of the subsea compressor. This includes large subsea transformers, power cables and terminations and high voltage wet-mate connectors, all of which are essential technologies for subsea substations for offshore wind application.
Today, the rapidly expanding offshore wind power industry could benefit from utilizing some of these high voltage power techonlogies recently qualified for subsea oil and gas processing applications. Many of the subsea power technological developments, skills and expertise gained in the oil and gas industry can be adapted for offshore wind application.
This paper presents the concept of a subsea high voltage substation applied to floating offshore wind parks. Both the system characteristics and the individual power technology features that are required to make the substation compact, efficient and reliable are emphasized. In addition, the differences and benefits of a subsea substation versus a floating substation will be highlighted.
Improve the Performance and Mitigate the Risk of Brownfield Infilling Project
Authors: Shi Hongfu , He Yifan , Luo Xianbo , Shu Xiao 
Published: April 2020

Abstract
The characteristics of a primary well pattern in offshore oilfields are: large well control reserves, large well spacing, thin well pattern, multi-layer combined production and develop highest quality reserves. Infilling adjustment project is of great significance for field life extension, full utilization of facilities, efficient production, remaining oil tapping, well pattern improvement, water flooding optimization, reservoir pressure maintains and production stabilization for offshore This paper takes an oil field in Bohai as an example to analyze the potential and risks of the infilling project.
Forecasting Intelligent-Well Completion Production through a Coupled Reservoir Model with Custom Functionality
Authors: Avila Juan Carlos 
Published: April 2020

Abstract
Intelligent well completion (IWC) or smart wells have been used in the industry for more than two decades. Numerous benefits from this technology have been reported in the literature. These benefits are associated with improved field development economics and better reservoir management. The field economics are mainly impacted by reduction of the well count and the increase of the estimated-ultimate recovery (EUR) and net-present value (NPV) by commingling different reservoirs. The reservoir management benefits are less tangible and more difficult to quantify. They have to rely on certain assumptions that may be controversial among the team members and management. Therefore, the IWC business case is usually supported only by the improved economics.
A key input on the economics is the production forecast. The industry lacks a standard workflow to predict the production from an IWC. Reservoir engineers have to be creative using their available tools to model the performance of this complex well operation. The methods regularly used are simple inflow-performance relationships (IPR), nodal analysis, well modeling with pipeline-network simulators, and 3D reservoir simulators with multi-segment well capabilities. The latter is the most appropriate to capture the value for new developments, but still extensive customization is required to optimize the production forecast while honoring all the constraints in the field operational philosophy; the others are more suitable for routine production optimization. In our case, deepwater Gulf of Mexico (GOM), the operating philosophy is (1) use primary well-head choke to control well production, (2) limit the pressure drop across the inflow-control valves (ICV), and (3) limit the producing zone drawdown. In addition, the productivity index (PI) degradation mechanism has to be included in the forecast. None of the commercial reservoir simulators have these requirements built-in.
This paper presents an approach that integrates detailed wellbore modeling, reservoir simulation, and the field operating philosophy. The workflow is based on a pipeline network simulator (GAP™) coupled to 3D reservoir simulation models in INTERSECT™. The IWC optimization under the operational philosophy is executed through a Python script—INTERSECT custom functionality—that manages the GAP network information obtained from OpenServer™ and the reservoir simulation data to select the ICV settings that optimize the well production while honoring all constraints. This workflow provides an accurate production forecast assuring all critical operating constraints are incorporated.