bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Sub-Scale Experimental Test Method to Investigate the Failure of Variable Ram Blowout Prevention Valves
Authors: Jayanath Shiyan , Huang Ming Yu , Mashue Aaron , Achuthan Ajit 
Published: April 2016

Abstract
The objective of this paper is to report the development and validation of a simple sub-scale experimental test method [1] capable of simulating the extrusion and sealing type deformation of a typical variable ram BOP during its closing stage. Initially, an investigation into the failure of an elastomer at room temperature using a sub-scale experimental setup was performed. Failure under both static and cyclic loading was studied. Maximum nominal operating strain of an elastomer, estimated by performing a finite element simulation of a full-scale closing operation, was used as the reference for the sub-scale experiment. Under static loading there was no visible material failure, and the material behavior post-test remained unaffected. Cyclic loading caused significant variation in the material behavior of the elastomer as the test progressed, which was later recovered progressively with time after the cyclic test. The study was then extended to high temperature conditions; 72 °C, 120 °C and 170 °C. Both at 120 °C and 170 °C, noticeable elastomer degradation was observed. Residual strains remained permanent for specimens tested at 170 °C even after a few days. An increase in sealing pressure was observed as the number of loading and unloading cycles progressed. However, these changes in the material behavior due to temperature were relatively small for 72 °C. Overall, the observed failure in the sub-scale test agreed very well with that reported for variable ram BOP devices in the field. Results from the present validation study indicate that the proposed sub-scale test is a promising method to investigate elastomer failure in BOPs under realistic field conditions.
Subsea Sampling Performed in the Deepwater BC-10 Field Offshore Brazil
Authors: Håheim S. , Dutsch D. , Pires L. , Baima J. , Galgoul D. , Caldas L. 
Published: April 2016

Abstract
The BC-10 O-North field is developed using water injection for pressure support. For reservoir management it is of substantial value to know the source of water observed in each well. Due to comingled wells and long flow lines, individual well sampling topsides is very difficult and give undesirable production deferment. To enable well fluid sampling from each individual producer, a subsea sampling access has been installed in Xmas tree. ROV deployed subsea multiphase sampling tools (SuMS Tools) have been developed, and a first subsea sampling campaign has been executed, retrieving samples from two individual wells in the BC-10 O-North field. The paper discuss the motivation for the sampling program, describe the sampling system, including Xmas tree modifications, sampling tool development and qualification, and describe the offshore execution of the first sampling campaign, with operational experiences and lessons learned. In addition to the technical content, this paper will also discuss the organizational and HSSE aspects of the sampling system and sampling process.
The technology used consists of a SuMS panel installed on the subsea Xmas tree, which enable access to the production flow when connecting the ROV manipulated SuMS tool. The well is kept producing during the tool connection, sampling period and tool disconnection, enabling a sample to be taken with stable flow conditions. After retrieval to the intervention vessel, the ROV tool with the sample is transported to shore, where the sample bottle is disconnected, and brought to a laboratory. In the lab, the fluids are separated into gas oil and water before being shipped to the analyses laboratory in the US.
The first sampling campaign was successful. The operation was performed efficiently, without any environmental or production impact, or damage to subsea hardware.
The SuMS technology is innovative, and is a significant step forward in reservoir management of subsea wells in cases where individual well sampling at the topsides facility is not feasible or desirable. It is also presented as an alternative to the use of test separators for MPFM calibration, preventing production deferment.
Subsea Compression – Åsgard Subsea Commissioning, Start-Up and Operational Experiences
Authors: Time N. P. , Torpe H. 
Published: April 2016

The Åsgard Subsea Compression (ÅSC) project has since project sanction in 2011 engineered, constructed, installed and commissioned the world's first Subsea Compression Station (SCSt).
The ÅSC SCSt includes two individual compressor trains, each containing an 11.5 MW centrifugal compressor module, condensate pump module, scrubber module and inlet- and discharge cooler modules. The compressor trains are installed at a water depth of 260 meters, in a shared subsea structure with a total weight of 5100 metric tons, a footprint of more than 3300 m2, and height of 17 meters above the seabed. The SCSt is connected to a subsea manifold station routing all flow from the wells via the compressor trains to the gas processing platform Åsgard B. The installation includes a comprehensive SURF scope with more than 60 km of new flow lines, 11 PLEMs and 50 tie-in points. The compressor station is powered from the Åsgard A FPSO where a separate high voltage power module weighing 850 metric tons has been installed. The subsea station is remotely operated from the Åsgard B platform.
The subsea compression station is compressing the gas flow from the Midgard and Mikkel reservoirs, boosting the production and securing stable flow conditions in the subsea flow lines towards Åsgard B.
The subsea commissioning has been carried out during summer, autumn and winter 2015/2016. It has involved control system commissioning, dynamic commissioning with N2 and MEG, before final commissioning with hydrocarbons. In order to secure efficient commissioning with involvement of a large number of vendors and support personnel, a remote operation room for the commissioning team was installed at Statoil's Stjørdal office outside Trondheim where the Åsgard Operations land organization is housed, thus avoiding constraints imposed by offshore training, helicopter travel and shortage of offshore cabins.
This paper describes the subsea commissioning phase, including experiences and lessons learned. Challenges including cooperation between onshore room, offshore platform, and installation vessel, as well as performing commissioning on one train with the other in operation, are discussed. In addition, it gives an outline of the experiences gained during the start-up and initial operation phases.
Turning FPU's into Hubs: Opportunities and Constraints
Authors: Yoshioka R. , S Swerdon A. Salem. , Loper C. , Pritchett W. 
Published: April 2016

Abstract
Offshore project capital costs have increased by an astronomical 400% forcing IOC's, NOC's and independent players to re-evaluate the feasibility and the profitability of some major developments. A decade long boom is now confronting unpredicted reality, altering the offshore development landscape and resulting in fewer opportunities and major consolidations in owners and contractors. Some owners are now shifting focus to brownfield and marginal field tie-backs to eliminate costs and risks associated with new installations. This paper explores one of those opportunities, namely turning Floating Production Units (FPU's – Semi, TLP, SPAR) into hubs, where various field owner/operators share production through the same FPU. Typically, hub developments are contracted under Production Handling Agreements (PHA). The PHA provides for price tariffs on produced oil, water and gas and is collected as the field owner/operator produces. Tariffs are paid for actual production which reduces reservoir production risk for large capex investments. Hub developments offer the field owner/operator the following value: Lower developmental CAPEX investmentReduced operating costsAccelerated development scheduleRisks and liabilities for decommissioning and poor well performance are reduced or eliminated.
Aspects of selecting the appropriate FPU are considered while presenting the suitability and limitation of each type for appropriate production sharing models. The paper will present a recent case study for a Semi-submersible designed with reserve topside, hull and mooring system capacity to meet tie-back requirements. The Semi- submersible is located in the deepwater Gulf of Mexico, at 6060 feet water depth, and approximately 145 miles southeast of New Orleans. The Thunder Hawk Semi-sub came online in July 2009. The unit has maximum oil production of 60,000bopd, and gas processing of 70mmscfd. Oil and gas is exported from Thunder Hawk via Steel Catenary Risers (SCR's) that connect into the export system. The recent tie-back to Thunder Hawk consists of three (3) wet insulated 8? SCRs, 8,500 psi. Three new wells are tied to the facility with capacity to produce up to 20,000 bopd each. The paper will focus on the technical and commercial constraints and opportunities employed to implement the tie-back, namely: engineering design, regulatory requirements, and production sharing philosophy.
Integrated Field Study Involving Downhole Fluid Analyzer DFA for Reservoir Connectivity in Thin Complex Lithology Formation: Case Study from Oman
Authors: Razvi Maria , Al Hadhrami Abeer , Al Shaibani Mohammed , Azzazi Mohammed , Frese Daniela , Al Bahrani Mundhir , Mohtadi Ashkaan , Al Mandhari Alyaqdhan , Daungkaew Saifon , Al Ajmi Issa , Al-Yaarubi Azzan , Zuo Julian , Mullins Oliver C. 
Published: April 2016

Abstract
Early information about reservoir fluid complexity, dynamic behavior, and reservoir connectivity is crucial for development planning and production optimization of new plays. Such impact is manifested in three main areas: (1) reservoir presence and connectivity to understand the extent of the play (2) reservoir fluid variation to understand the charge history and devise production strategy (3) completion optimization in exploration wells to maximize early production.
Petroleum Development of Oman pursued an ambitious exploration campaign firstly consisting of 8 wells targeting a shallow, thin, complex lithology formation to better understand a new play, especially from reservoir extension and connectivity viewpoints. In addition to advanced formation evaluation logging consisting of elemental spectroscopy and nuclear magnetic resonance, an advanced Downhole Fluid Analyzer (DFA) was deployed with Wireline Formation Testers (FT) aimed to obtain formation pressure and fluid samples. The fluid scanning using in-situ fluid analysis was also performed to obtain reservoir fluid information in real time and at reservoir condition. In addition, Interval Pressure Transient Tests (IPTT) was conducted to evaluate permeability of each well.
This paper provides the workflow of using the DFA and laboratory data for full field development. This will include discussion of DFA data such as asphaltene, fluid composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help draw a full picture towards reservoir connectivity.
Having detailed fluid properties data available in real time allows to optimize the completion decisions (pump selection as one example) in order to maximize early production while allowing longer term reservoir management planning. This paper also discusses the use of in-situ fluid viscosity and pressure transient data to estimate zone permeability during the FT operation, which will later be compared to actual well test data. Results show a good comparison and provide comfort to use FT pressure transient data to evaluate zone permeability at early stage of the operation.
The DFA data from the first 4 wells suggested the presence of subtle but distinct fluid differences in terms of composition, oil color, and fluorescence yields. This DFA data was then supported by full PVT laboratory results. The differences in fluids will be examined in more details. This paper will present an effective workflow to integrate pressure, DFA, and PVT data to understand reservoir connectivity issue in this newly discovered formation. In addition, the DFA color gradient model was then used to help supporting other available information.
Using Electro Active Polymers to Transform Wave Energy Conversion
Authors: Wattez Ambroise , van Kessel Rick 
Published: April 2016

The first generations of wave energy converters have had a number of forms, but all are essentially large steel structures concentrating the power take off onto small mechanical devices. A number of prototype devices have been installed offshore, but due to their high fabrication and installation costs, coupled with significant maintenance requirements, the production of electricity at an acceptable cost has remained elusive.
To avoid the limitations of these devices, a second generation wave energy converter is being developed using electro active polymers (EAP), which are capable of generating electricity directly from wave action without the need for any mechanical power take off. The resulting system is flexible and possesses an infinite number of degrees of freedom, allowing wave energy to be captured more efficiently than with conventional devices. Deployed offshore, such a device would have no complex mechanical parts, would function silently, and would require minimal maintenance. The economics of such a system lead to predictions of a cost of electricity significantly below the levels of the first generation devices.
The paper explains the principals involved in using EAP for the generation of electricity, the application of EAP to wave energy conversion, and reports key results from the ongoing development program. The paper also describes the main features of the prototype wave energy converter system presently under development for deployment offshore.
Advantages of Applying a Multifaceted Approach to Asphaltene Inhibitor Selection
Authors: Bae Jaehoon , Fouchard David , Garner Susan , Macias Jose 
Published: April 2016

Abstract
The right Asphaltene Inhibitor (AI) selection is crucial for the control of asphaltene issues in oil production. Although many factors contribute for the asphaltene precipitation/deposition in the fields, the chemical selection process in the laboratory were often conducted only under ambient temperature and pressure. In this paper, we introduced a multifaceted approach for asphaltene inhibitor selection process to overcome the test condition discrepancy between laboratory and the fields. The importance of temperature on the performance of chemicals was evidenced by our high temperature optical scanning device results. The Coupon Deposition Test (CDT) clearly demonstrated the difference between deposition and precipitation behavior and the impact of the water phase on inhibitor performance. High pressure Asphaltene Rocking Cell (ARC) enabled to incorporate high pressure, high temperature and water conditions in the laboratory to show the difference of inhibitor performances. By incorporating field conditions such as temperature, brine composition and pressure into our tests, better recommendations can be achieved that would have not been possible with any optical, precipitation based technique. Furthermore, a suite of AI test methods which cover various field conditions brings a degree of refinement in product selection unmatched by any single method and allows for selection of the best asphaltene chemical program for a particular field through its life cycle.
Qualification of Composite Pipe
Authors: Wilkins Jonathan 
Published: April 2016

Magma Global manufactures a thermoplastic composite pipe for use in high performance riser, jumper spool and intervention line applications. m-pipe® is a unique product manufactured from PEEK, carbon fibre and glass fibre materials using an automated laser-based welding process.
Managing the qualification of new technology is a significant challenge. Magma must demonstrate the reliability of m-pipe® to its customers, to third-party assessors, and to the regulators. Since thermoplastic composite pipe is a new area of technology, Magma has combined the guidance from a newly published DNV recommended practice [1] with a risk based approach to qualification management [2].
This paper gives a summary of the approach used by Magma to qualify m-pipe®. It describes the methods used to:
Identify and mitigate risks in the design and manufacturing processes.
Comply with relevant requirements from existing codes and standards that are applicable to the design and qualification processes.
Develop test procedures to evaluate both fundamental material behaviour and structural behaviour of the complete product.
Develop analysis models and design tools based on learnings from the testing.
Collaborate with suppliers, operators and other manufacturers to develop a new standard specifically related to m-pipe® type thermoplastic composite pipes.

It is hoped that these learnings will be useful to others in the wider oil and gas community who are working on the development of novel materials technology.
Development and Engineering of Offshore Mining Systems - State of the Art and Future Perspectives
Authors: Knodt Steffen , Kleinen Torsten , Dornieden Christian , Lorscheidt Jan , Bjørneklett Børge , Mitzlaff Alexander 
Published: April 2016

Abstract
This paper gives a brief overview on the major milestones of the deep sea mining projects in the 70's and 80's with focus on the OMI/OMCO-Consortia and the engineering milestones SEDCO 445, Hughes Glomar Explorer, Clementine II and PLA2 6000, the pilot mining tests of the AMR, the environmental study DISCOL and the joint efforts of Gemenod/Preussag. Among the most interesting and technologically challenging systems are those for deep sea mining of manganese nodules in water depths of 4,000 to 6,000 meters in the Mid-Pacific. Following the total integrated systems (TIS) approach, the technology transfer between ultra-deep water drilling and deep sea mining is outlined based on several subsystems and specified for the key components of the vertical transport system. As example for state of the art engineering and technologies recent developments of heavy-load active heave compensated drawworks, ultra-deep water riser systems, motion-compensated offshore mining drill pipes with air-lift slurry transport, remote subsea workclass-crawler ISUP and the Korean manganese nodules collector MineRo II are described. Based on the principles applied for development and engineering of systems for shallow water offshore mining and the experiences available from the pilot mining tests conducted in the past, a concept for an offshore mining system was developed by MHWirth in corporation with the German Federal Institute for Geosciences and Natural Resources (BGR). This concept will be outlined in the current paper together with the main results of an economic feasibility study. Furthermore, an overview on the current European deep sea mining research projects and a renewed German-French industrial cooperation is given. Synergies with the emerging private space industry are anticipated regarding systems engineering. Future perspectives for a new pilot mining test are discussed.
Performance Evaluation of Recently Developed Soil Models in Well Conductor Fatigue Analysis using Field Measurements
Authors: Kannala Jomon , Zakeri Arash , Long Ge Michael , Buba Kebadze Elizbar 
Published: April 2016

Abstract
American Petroleum Institute (API) [2] recommendations for modeling the lateral soil resistance-displacement (p-y) response were not developed for fatigue analysis of deepwater wells. The recently developed soil models [1] is aimed to fill this knowledge gap. Based on extensive physical testing in a geotechnical centrifuge and complementary numerical modelling, a more accurate approach was developed for soil modeling specific to well conductor fatigue analysis. The approach was presented at OTC2015 [1]. While the approach proposed in [1] performed very well in predicting the fatigue damage in the model tests, its performance is yet to be evaluated against actual field data obtained in the field. This paper evaluates the performance of the recently developed soil models in predicting field measurements and fatigue damage obtained from a monitored well in the Gulf of Mexico (GoM). Important considerations for modeling soil response (e.g., modeling of soil crust near mudline) are also discussed. The new approaches are applicable to fatigue analysis of conductors pertaining to subsea wells worldwide. The motion monitoring loggers collect acceleration and angular rate information at the point of installation. The objective was to investigate the fatigue performance of the wellhead and conductor system. Fatigue was estimated based on the motion data collected from the data loggers. The measured motions and fatigue damage obtained from the loggers were compared to those estimated from predictive methods using the proposed soil model. This paper demonstrates that the recently developed soil models perform satisfactorily in predicting the deformations (displacements and rotations) measured at the top of the lower marine riser package (LMRP); hence, providing a more accurate prediction of the system (LMRP, wellhead and casings) response and thereby, its fatigue damage.
Power Generation Interconnection Between 2 Existing Deep Offshore FPSO's a World First
Authors: Leforgeais Bruno , Bourgogne Olivier 
Published: April 2016

This is the worldwide first-ever Power Interconnector between Deep Offshore FPSOs, i.e. over the two Girassol and Dalia FPSOs, including the integration of an Integrated Power Management System, together with Load Sharing and Load Shedding that has enable the implementation of subsea multiphase pumps to enhance oil recovery.
This paper presents the overcome of technical challenges the project team has met on very different aspects of the execution phase: innovative design such as Dynamic Section studies and thermal studies of Interconnecting Power Cable, Prevention of excessive voltage drop during the magnetization of the 33kV power interconnector, and testing & energizing strategy such as Management of dissimilar Power Generation, Short circuit level limitation.
High Boost Multiphase Pumps: The Challenges of Flow Assurance and Operation
Authors: Le Rodallec Jean-Luc , Delourme Cecile 
Published: April 2016

The implementation, after 8 years of production, of four High Boost MultiPhase Pumps (MPP) within an existing subsea installation not originally designed for, modifies deeply the flow assurance and the way of operating the Rosa fields and the Girassol FPSO, to which the production loops are tied-back.
Thanks to an extensive flow assurance program launched at the project kick-off, design optimizations were proposed, verified and tested through dedicated simulations during project studies and execution.
On top of the design, this paper shows how the results and conclusions of these studies were translated into operating procedures, training simulator and up to the maintenance program.
Effective and Innovative SIMOPS Management: A Key to Minimization of Production Shortfalls Associated to Deep Offshore Subsea and Drilling Brown Field Activities
Authors: Kiehl Vincent , Alexandre Celma , Ferreira Elgar , Dembele Marcel 
Published: April 2016

By definition Brownfield projects are executed on facilities in production, with inherent risks and constraints. The Deep Offshore dimension increases the complexity of these activities with the construction and installation work carried out on live subsea networks and FPSO's. Very often with drilling rigs operating on the location and sometimes in parallel with maintenance and integrity works.
The key for safe and successful Brownfield activities, minimizing the production losses caused by required shut-downs, goes consequently through a specific management of these Simultaneous Operations (SIMOPS).
This paper presents the SIMOPS management principles implemented in TOTAL E&P Angola for Brownfield activities executed on FPSO's and their subsea network, along with different innovations recently introduced to further optimize the requirement for production shut down.