bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Will Subsea Processing and Pumping Technologies Enable Future Deepwater Field Developments?
Authors: Kondapi Phaneendra. B. , Chin Y. Doreen , Srivastava Ashesh , Yang Zuying F. 
Published: April 2017

This is a study on how subsea processing be the enabling technologies for future ultra-deepwater field developments and long distance tiebacks. This study identifies the gaps that need to be closed and decision making process during the field development life cycle by considering both the technical and economic constraints of various subsea processing technologies. As E&P companies continue to explore for oil & gas deeper and further into sea, the challenges associated with developing the deepwater fields are bound to escalate. Subsea processing technologies are the fastest growing technologies due to their huge potential to increase recoverable reserves and to accelerate production. It also enables for cost saving by moving some of the traditional topsides processing to seabed. As the reliability of subsea processing equipment is increasing, the industry is gaining more confidence in subsea processing. As industry gains more experience of design and operating subsea processing technologies, and closing the gaps, it improves understanding of the technology and making advancement to counter the challenges associated with harsher environments and complex fields. Properly-designed modularized compact subsea processing kits can be economic to deploy, and may potentially become an enabler for certain types of marginal field developments.This paper addresses the challenges of reservoir characteristics and fluid properties, cost, risk, reliability, operability, installability, maintainability and intervention complexities; assesses the existing and emerging technologies; focuses on improving efficient compact design to reduce bulky and heavy equipment, achieving separation from heavy oil, and disposal of separated water. Certainly there are limitations in making the subsea processing viable and accessible to all operators but the technology needs and industry collaboration should overcome these challenges. Also there are opportunities for improvement and standardization, and modular design processing systems for reservoir suitability, field layout and topsides support.
Design Challenges for Power & All Electric Control Umbilicals
Authors: Dobson Alan , Deighton Alan 
Published: April 2017

Since the first umbilicals were developed and installed to control and preserve subsea equipment they have continued to evolve to ensure effective operation in an increasingly challenging subsea environment. New material technologies, complex analysis tools and umbilical designs, such as in , have been developed to ensure umbilical systems operate through-out their service life irrespective of the ambient temperature, fatigue loading, hyperbaric pressure and tensile loads applied.
Typical Control and Chemical Injection Umbilical Arangement

The subsea industry needs to adapt to the challenge of reducing capital expenditure (CAPEX) costs due to reduced oil price. The potential cost savings could be realised through adapting the subsea processing system to treat processed fluids on the seabed together with utilising longer step out systems from existing facilities. This could drive a new step in umbilical evolution.
To support the potential evolution of subsea processing systems, the conventional control umbilical must evolve to incorporate the supply of electrical power and potentially electrical control to replace hydraulic control over long step out distances. This has a significant influence on the design of the umbilical system, introducing several new challenges which need to be addressed through material selection and advanced analysis techniques.
This paper will provide an overview of the potential evolution of the Next Generation All Electric umbilical and outline the design challenges and methods developed to maximise the reliability of the umbilical system.
Flow Assurance during Deepwater Gas Well Testing: Addressing Hydrate Associated Problems at Reduced Cost
Authors: Zhao Yang , Wang Zhiyuan , Zhang Jianbo , Pan Shaowei , Yu Jing , Sun Baojiang 
Published: April 2017

Abstract
Hydrate formation/blockage causes serious flow assurance issues during deepwater operations (e.g. well testing). Current dominant method is total prevention of hydrate formation with massive thermodynamics inhibitors (THIs), which render this method economically infeasible. Moreover, the required inhibitor storage and injection capacity may be far beyond the facility limits when the water production rate is high. In this work, aimed at addressing hydrate associated problems at reduced cost, a method is developed to prevent hydrate blockage with lower inhibitor consumption. Based on hydrate formation and deposition dynamics, a method is developed to prevent hydrate blockage during deepwater gas well testing. Implementation procedure of the proposed method is developed and further illustrated through case studies. We recommend that testing operations should be run within the Hydrate Blockage Free Window, HBFW. The HBFW refers to the period from the beginning of testing operations to the moment when a significant pressure drop increase is encountered. Case study work is conducted on a deepwater gas well in the South China Sea. The case study suggests that hydrate inhibitor can postpone the occurrence of conduit blockage. When the scheduled operation time (SOT) is shorter than the HBFW, the testing operation can be completed within the HBFW and no hydrate inhibitor is needed. If the SOT is longer than the HBFW, a small amount of inhibitor is required to extend the HBFW, thus the testing operation can be completed within the HBFW. The inhibitor consumption is much lower compared with the current over-inhibition method. With the proposed HBFW-based method, the inhibitor storage/injection capacity requirement can also be relaxed. The study suggests that with lower inhibitor consumption and inhibitor storage/injection capacity requirement, the HBFW-based method can address hydrate associated problems during deepwater gas well testing at reduced cost. In addition, the reduced inhibitor storage/injection capacity requirement makes this method more feasible especially when high water production is encountered during testing operations.
Experimental Investigation of Severe Slugging Control by Surfactant Injection
Authors: Barreto Carolina V. , Pimenta Amanda , Karami Hamidreza , Pereyra Eduardo , Sarica Cem 
Published: April 2017

Recently, with the ever-increasing development of offshore fields, the use of long risers fed by lateral flow lines has significantly increased. This type of configuration exposes the production system to severe slugging, particularly with decline in reservoir pressure and consequently flow rates. Severe slugging can cause huge pressure fluctuations and may result in decreased recovery and separator flooding. This study is an experimental and theoretical effort to analyze how the application of surfactants can suppress or eliminate severe slugging.
The experimental study is performed in a 2-in ID facility, consisting of a 64-ft flow line with 1° downward inclination, followed by a 41-ft riser. Water and compressed air are the liquid and gas phases, and an anionic surfactant is applied continuously. First, effects of surfactant delivery location are investigated by injecting at three points, namely, riser base and flowline inlet without or with a static mixer, used as an external source of agitation. Pressure and holdup fluctuations with time, slugging frequency and surfactant efficiency are monitored. Moreover, a high-speed camera is used to monitor blowout stage and analyze gas front thickness and velocity. Pressure fluctuations and surfactant efficiency are experimentally investigated by changing the operating conditions. Tests include without and with surfactant at different liquid and gas flow rates.
Firstly, the experiments are conducted with lowest superficial gas velocity (vSg) and highest superficial liquid velocity (vSL) values. At these conditions, severe slugging is partially eliminated only with high surfactant concentration and the use of static mixer. The use of surfactant in other locations results in elimination of slug production stage and reduced cycle duration, but negligible changes in pressure profile. Then, a new test matrix is designed to conduct tests at higher vSg and lower vSL values, moving towards the boundary of Bøe's criterion for severe slugging. Under these conditions, severe slugging cycle durations and pressure fluctuations reduce and elimination efficiency of surfactant increases significantly. In addition, severe slugging severity and elimination efficiency are correlated with Boe's criterion coefficient.
This study is an attempt to characterize severe slugging magnitude based on operating conditions, and investigate surfactant efficiency for different delivery locations. Considering the limited number of studies on this subject, the results can provide an experimental and theoretical source to optimize surfactant application in production systems facing severe slugging.
Comparative Economic and Technical Evaluation of AG FGTL Floating Gas to Liquid Vessel vs. AG FLNG
Authors: Nguyen Xuan Chi , Mihaeye Komla , Shim Woolyong , Lee Charles 
Published: April 2017

Abstract
This study presents a comparative evaluation of a Floating Gas to Liquid Facility (FGTL) and a Floating Liquid Natural gas Facility (FLNG) as a way to monetize Associated Gas (AG) from existing oil producing offshore fields or from remote offshore gas fields. The study aims at showing that the FGTL is an option to be considered as a way to monetize AG.
For this purpose, a previous study presented to the OMAE under OMAE2016 – 55152 is used for the FLNG with one liquefaction train for nitrogen refrigerant. This FLNG concept serves as a benchmark to evaluate the technical and economic relevance of the FGTL through the Net Present Value (NPV) of the Life Cycle Cost (LCC). The LCC compares the difference between the FGTL and the FLNG NPVs on the basis of a selling price for the gasoline of 1.4, 2.0 and 2.4 USD/Gal with a price for the LNG varying from 3.5 to 7.5 USD/MMBTU.
The AG FGTL is presented in detail with a capacity of 6,000 bpd of gasoline (methanol production being an option to Gasoline). Natural gas is converted into gasoline by a proprietary natural gas to Liquids technology awarded with AIP (Approval In Principal) by ABS for off-shore GTL, which includes five principal steps in one continuous gas-phase process loop using only standard components: (1) Steam Methane Reforming; (2) Methanol Synthesis; (3) Gasoline Synthesis; (4) Gasoline Treatment; (5) Separation. This proprietary technology has several advantages over other GTL technologies including single product, long catalyst lifetime and higher allowable levels of CO2 in AG. Gasoline produced using a proprietary natural gas to Liquids technology can be blended with refinery gasoline or sold directly into the wholesale market.
Subsea Power JIP - As Enabler for All- Electric Subsea Production
Authors: Bugge J. Ø. , Ingebrigtsen S. 
Published: April 2017

The journey towards the realization of the subsea factory is well on its way, promising the benefits of subsea processing and production. This "Grand Challenge" places extreme demands on the reliability, uptime and safety of the technology for distributing, delivery and control of the power system.
ABB Oil & Gas is running a Joint Industry project together with Statoil, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion at greater distances, in deeper waters, and in harsher environments. The project started up in 2013 and is targeting a 3000-hour shallow-water system test in 2018, including the qualification of pressure tolerant medium voltage switchgear, medium voltage drives, as well as supporting controls and auxiliary supplies.
The project budget is in excess of 100 MUSD, funded by ABB, Statoil, Total, Chevron as well as The Research Council of Norway. The target environment is water depths up to 3000 meters, transmission distances up to 600 km, and power levels up to 100 MW.
The project follows the TRL development stages for technology qualification applied to components, sub-assemblies and equipment. This is a systematic approach ensuring that the technology will function reliably within specified limits, and it provides a common understanding and terminology of technology status and risk management. Qualification includes extensive testing of components subjected to test conditions derived from a common understanding of realistic component/equipment specific stresses throughout an agreed life-cycle mission profile, with particular emphasis on learning the behavior and limits of different designs. Comprehensive confirmation of the desired function as well as reliability testing is primarily conducted at the level of the component where a functional failure can be defined and accelerated conditions applied. Further, we perform sub-assembly testing mainly geared toward confirming the overall function, design margins, and the thermal and high-current performance. Formal qualification of key components and sub-assemblies is planned for 2017. Based on qualified components, final prototypes will be assembled in 2018 for a 3000 hour shallow-water endurance test and system demonstration.
The project passed a decision gate milestone in April 2015, having verified technology concepts as well as TRL2 for key components. Prototypes under development include full-scale subsea drives and switchgear with supporting controls and LV auxiliaries and functional verifications in key ABB factories. During 2016 key prototype designs have been tested and functionally demonstrated over a limited operating range. This paper provides a summary of the current status of the project highlighting the most critical areas for success, such as designing for modularity and the demanding reliability and availability targets, and utilizing the best experts and experience across ABB as well as the participating oil companies.
Euryale Moonpool – Innovative Naval Architecture Design Enables Full Dual Drilling Accessibility on a Drillship
Authors: Hendriks Sjoerd , Man Pieter de , Zijderveld Govert , Diemen C. van 
Published: April 2017

The offshore drilling market is pushing for more cost efficiency, more efficient drilling packages and more safety and redundancy, but also have the desire to be able to drill and develop more complex wells in deeper water. New concepts and designs will be needed to meet these challenges and make drilling complex and deeper wells commercially attractive.
A rig design solution to provide increased drilling efficiency is to set up the rig for full dual drilling featuring two fully equivalent well centers. This will combine the benefits of dual activity with additional rig flexibility and redundancy. In the existing configurations well centers are mostly not equivalent, as for example with the commonly used main or auxiliary hoist, specific operations are be limited to only one well center. When aiming for full interchangeable well center functionality, at all times full accessibility to both well centers is required, at drill floor level as well as in the moonpool. This arrangement does not exist on earlier or contemporary drillship designs. In general a drillship features ample deck space, but the vessel deck areas and the well centers are longitudinally arranged. This causes the forward well center to block access from the forward deck area to the aft well center, and vice versa.
By breaking with traditional naval architectural thinking patterns, an innovative approach to the drilling process in a moonpool arrangement is introduced. It comprises a transversely oriented moonpool, named the Euryale moonpool concept. The Euryale concept allows the well centers to be transversely arranged, and thus providing the right accessibility to both well centers on the drill floor as well as in the moonpool from forward and aft deck areas, ensuring all advantages of full dual drilling and full redundancy on a drillship.
The (patent pending) Euryale moonpool features not only full dual drilling accessibility, it also mitigates sloshing motion in the moonpool during transit due to the significantly reduced length of the moonpool. The calm water in the moonpool not only creates a safer working environment for high value equipment and personnel, it saves fuel cost and reduces emissions as well. The Euryale moonpool is integrated in the ship's structure ensuring the overall integrity of the drillship, and does not contain any failure sensitive underwater mechanical parts nor protruding parts in the moonpool that might impose damage on the deployed riser.
A patent has been applied for the Euryale moonpool.
Response of Vertically Loaded Centrifuge Suction Caisson Models in Soft Clay
Authors: Wallace J. F. , Rutherford C. J. 
Published: April 2017

Abstract
Tidal current turbines are designed to interact with flowing water. This interaction results in a significant horizontal load and corresponding overturning moment that can be resisted through a compression and tension mechanism on opposing foundation legs if the foundations are configured as a multipod. This study investigates the response of suction caisson foundations in soft clay with an aspect ratio of one to this compression and tension loading by means of centrifuge testing.
Suction caisson models with an aspect ratio of one were fabricated out of T6-6160 aluminum at a scale of 1:90 and tested in kaolin testbeds. The kaolin testbeds were consolidated from slurry under an effective stress matching the effective stress at the mid depth of the testbed when spun at 90-g. A series of monotonic vertical load tests were conducted at 90-g on a beam centrifuge using a vertical stepper motor. The series of load tests comprised of undrained monotonic loading phases conducted both prior and post long period cyclic load phases corresponding to the longer period components of tidal current velocity fluctuations.
Geotechnical centrifuge testing allows for the investigation of suction caisson response under loading conditions applicable to tidal current turbine structures under realistic stress and stress distritbutions by artificially increasing the gravity. The response of the suction caisson under vertical monotonic loading without any prior cycling provided a baseline case for determination of the effects of long period cycling (i.e. semi-diurnal tidal current fluctuations) on future monotonic undrained loading. The load tests showed that the effects of long period cyclic loading on the degradation of the undrained monotonic capacity were dependent on the amplitude of the cyclic loading. The cyclic strain thresholds that caused a significant decrease in the post cyclic monotonic capacity were not the same for compression and uplift loading mechanisms. This indicates that serviceability constraints will play a critical role in tidal current turbine foundation design. Ensuring reliable foundation design will allow for cost efficiency during construction and over the lifetime of the tidal current turbine structure.
As tidal current turbine technology, at this time, is primarily in the prototyping stage, it is key to understand the response of the foundations to these loading conditions in order to increase the cost efficiency of the overall structure.
World-First All-Electric Subsea Well
Authors: Schwerdtfeger Thomas , Scott Bruce , Akker Jan van den 
Published: April 2017

K5F3, the world's first fully all-electric well of the subsea industry, has been opened to production on 4 August 2016.
This paper will present the benefits of electric subsea control compared with current state-of-the-art hydraulics methods, describe R&D projects that led to this first industrial application, and outline the main project phases and milestones. Difficulties encountered will be presented, and lessons learned will be disclosed. Finally, this paper will present future plans for subsea electric control going forward.
The current state of the art for subsea well control is based on hydraulic technology. Hydraulic fluid is supplied from a host facility to the subsea wells through dedicated tubes within an umbilical and is distributed to the wells, in which the typical components are the manifold, Christmas tree valves, and downhole safety valve.
The all-electric subsea well consists of an electric subsea Christmas tree, electric downhole safety valve, and associated subsea control modules. Valve control is established via an electric cable.
The main driver for this innovation is cost reduction. Umbilicals are complex, difficult to install, and highly expensive. Replacing hydraulic fluid tubes by an electric cable within the umbilical can provide a 15% cost savings over a 30-km step-out. Implementing electric technology for Christmas tree valves and downhole safety valve control can also generate a further 10% cost reduction. All-electric subsea control is also an enabler for subsea processing innovations for more cost-effective subsea developments in a low oil price context. A global 30% to 40% reduction, outside of market effects, is the goal. This technology improves control of environmental impact by removing the risk of hydraulic fluid release, and personnel safety is improved with the removal of high pressure equipment and containment on topside facilities. Finally, electric technology demonstrates higher reliability compared to hydraulic systems and offers less complex subsea distribution and simpler hardware components.
Electric Christmas trees have been successfully operating on two wells of the K5 field offshore Netherlands since 2008, and the electric downhole safety valve has been developed. Although K5F3 is a subsea well in a shallow-water environment, all components have been qualified for 3,000 m of water. In 2015, the global control system has been fully qualified and successfully tested through factory acceptance testing (FAT), extended factory acceptance testing (e-FAT), and site integration testing (SIT). The well was spudded early 2016, completed in June, and successfully put on stream in August.
Electric control of wells is already taken into account for conceptual development studies and will become the base case for all of one operator's deep offshore projects when K5F3 demonstrates the efficiency of the technology.