bluuebunny/crossref_metadata_2025_split huggingface dataset:
ECD Management Toolbox for Floating Drilling Units
Authors: Godhavn John-Morten , Hauge Espen , Molde Dag Ove , Kjøsnes Ivar , Gaassand Sturle , Fossli Statoil Børre , Stave Roger 
Published: June 2014

AbstractThis paper presents ongoing work as well as plans and ideas for future development of a toolbox of managed pressure drilling systems that solves major challenges when drilling in both mid- and deep waters. The toolbox contains three applications based on field proven Controlled Mud Level (CML) technology. Additional benefits can be achieved by combining controlled mud level technology with other technology elements such as a fast closing annular or a sealing element in the riser, usually referred to as a rotating control device (RCD).The first application is called CML. A subsea pump module (SPM) is used to pump the mud returns to surface in a separate mud return line (MRL). The SPM is used to regulate and manage the bottomhole pressure by adjusting the mud level in the riser. High bottomhole pressure or Equivalent Circulating Density (ECD) due to friction and other effects can be avoided by reducing the mud level in the riser accordingly. One of the objectives with this technology is to avoid or reduce losses both during drilling and other operations such as cementing.In the second application called ECD-Management, CML is combined with a fast closing annular installed in the riser just above the SPM. This enables extending the operating envelope of the technology to a point where loss of circulating capability could potentially cause an underbalance scenario in the well. The hydrostatic pressure from the drill string or MRL can be trapped within a few seconds by closing the fast closing annular element, e.g. on unplanned rig pump stops or formation pack off situations. A second annular will also be installed to be used during connections in order to save time filling up the riser to compensate for the ECD effect (friction losses in the annulus).The third application in the toolbox is called ECD-Control. Here a subsea RCD or a sealing element is installed in the riser and the SPM can then be used to manipulate the pressure below the RCD to compensate for ECD variations. The riser is always topped up with mud and hydrostatic overbalance is maintained.The paper will present simulation results comparing the different technologies and address benefits and challenges with the different methods.
Assessment of Ultra Deepwater Riser Concepts for High-Motion Vessels
Authors: Royer Brian S. , Power Thomas L. , Ayewah Daniel O. , Head William 
Published: June 2014

Abstract
The paper presents the results of the second half of a study funded by Research Partnership to Secure Energy for America (RPSEA) under project 10121-4401-02 Ultra-Deepwater Riser Concepts for High Motion Vessels. In the first half of the study, candidate riser systems consisting of alternatives to the steel catenary riser in both geometry – for the purpose of isolating the fatigue-critical riser touchdown zone from the motions of the vessel – and material were identified then down-selected to meet the constraints of high motion vessels like the conventional semi-submersible or a ship-shape floating, production, storage, and offloading vessel (FPSO). In addition to water depths approaching 10,000 feet, the present-day challenges of high pressure, high temperature, and sour well product are incorporated into the problem being framed.
Results from dynamic analyses of riser concepts passing through the down-selection process are used to assess both utilization of strength capacity and fatigue performance. Comparisons of dynamic responses highlight the differences of each riser concept's behavior and provide understanding of the limitations of riser concepts. Assessments to other criteria such as cost, failure modes, and installation considerations are also used to ascertain safe riser systems that meet the performance demand of high-motion vessels.
Subsea Compact Separation: Control System Design
Authors: Li Z. , Olson M. , Rayachoti V. , Gupte P. , Pierre F. , Gul K. 
Published: June 2014

AbstractThis paper summarizes key results of the development and verification for a subsea compact separation control system based upon a literature review, control system design, dynamic simulations, and an integrated system test. The compact separation system being considered is designed for applications in water depths up to 3,000m. The control system is a key technology element of the compact separation system, and its satisfactory performance is critical to ensure stable operation of the overall system. A thorough literature review was conducted to evaluate the control system designs for comparable subsea separation systems in industry, to understand the technical challenges, and to incorporate the key learnings into the development of this control system design.From this work, best practices were identified and were used as guidelines. A preliminary control system was developed, and the robustness of its design was assessed through dynamic simulations. Later, an integrated system test was performed with real crude and methane at realistic operating conditions to evaluate the performance of the compact separation equipment and to validate the model of the control system. The dynamic simulations and integrated system test results demonstrated the control system response following transient events, such as slugging, and provided insight into the system dynamics that then led to further modifications of the control system design and enhanced the overall system performance.This paper also delineates challenges associated with the design of a control system for a subsea compact separation system consisting of multiple, closely integrated gas-liquid and oil-water separation units. For example, the relatively small control volumes in compact separation equipment and the interaction between the different components can both add complexity to the control system design. Lessons learned from the modeling and implementation of such a sophisticated control system are discussed with the intent to serve as a reference for future subsea separation projects in the oil and gas industry.
New Polymeric Materials Development for Extreme Environments
Authors: Drake Kerry , Callaway Ron 
Published: June 2014

Abstract
Extreme environments are becoming more and more common as oil exploration and production moves to deeper reserves that have increasingly higher bottomhole temperatures and pressures. Development of successful products for extreme environments demands a detailed understanding of both application requirements and materials engineering. Often, current materials and current designs do not fully address the needs of new applications in extreme environments. Therefore, new materials and new design tools are needed. A review of the processes used for selection and development of polymeric materials and predictive models for product performance in extreme environments will be presented. A general discussion of oilfield product requirements and performance characteristics of PEEK and PEK will be reviewed as a starting point, to show why these materials became dominant in specific oilfield applications. Findings generated from failure analyses of field samples, and research on conditions in extreme environments (HPHT) will be reviewed and used to help target key characteristics for new materials development.
Capabilities developed to perform testing under simulated conditions and generate accurate predictive models are key tools in the design and evaluation of new materials. Material and product testing of a new patent-pending polymer developed using these tools will be presented. Test results from current best-in-class materials PEEK and PEK in both coupon and product form will be contrasted with results from the new polymer. The superior performance of the new polymer over best-in-class polyketones validated this experimental approach. This new material should provide enhanced reliability for oil and gas engineers when used to replace other materials for components used in demanding high-temperature and high-pressure service.
A Completion System Application for the World's First Marine Hydrate Production Test
Authors: Matsuzawa Maki , Terao Yoshihiro , Hay Bill , Wingstrom Luke , Duncan Mike , Ayling Ian 
Published: June 2014

Abstract
The world's first subsea methane hydrate completion system was installed and its production test successfully executed in the eastern Nankai Trough area off the east coast of central Japan in March 2013.
A variety of methane hydrate production methods exist and have been recognized by the industry as being feasible in producing methane hydrate from the view point of geology, geophysics, petrophysics and reservoir/production engineering. This paper describes one of these methods and provides some background and detailed engineering required in the development of a completion design, the interface and qualification testing necessary to mitigate some key challenges and risks associated in the development of a methane hydrate completion and production system. The completion system demonstrated in this paper utilizes an Electrical Submersible Pump (ESP) in conjunction with real-time downhole monitoring whilst producing separated fluid and gas flow streams to surface, combining natural and artificial separation methods.
The objective of this paper is to present the application of the completion system in a methane hydrate production well by the depressurization method. It will review the completion system and key production string component, as well as the lessons learned from the production test.
Direct bonding, adhesive-free Multilayer Thermoplastic Systems for Oil & Gas Pipelines, Risers and Umbilicals
Authors: Berger Jan , Franosch Juergen , Dowe Andreas 
Published: June 2014

Abstract
Since the 1970ies, Multilayer Thermoplastic Systems have been a success in many applications, from food packaging films to automotive fuel hoses and tanks. The great advantage of these systems is to combine the strengths of its single materials, from mechanical strength and chemical resistance, ductility and crack resistance to price. In those industries, Multilayer Technology is state of the art and you can hardly find single material solutions any more.
Although these advantages perfectly match the requirements of oil and gas applications, tough conditions combined with long lifetime requirements and expensive qualification programs have limited the use of multilayer systems up to now. As conditions are getting even tougher, sometimes a single material solution cannot meet the requirements any more. On the other hand, Multilayer Technology has been developed further and can now meet all requirements of the oil and gas industry.
The authors will introduce two different multilayer systems based on Fluoropolymer – Polyamide combinations. As all combinations provide bonding without having to use an adhesive layer, delamination because of adhesive layer errors are impossible. As delamination of the direct bond after rapid gas decompression has been defined as one of the key show stoppers for multilayer systems used in pipelines and risers, development work first has been focused on RGD performance. The testing setup including peel testing and results will be shown. After that, further testing on the systems has been performed, for example chemical resistance testing, permeation tests and bonding performance over time in accelerated aging conditions. Another important development step has been to make the materials extrudable in large diameters and compatible to each other in processing.
Both systems offer significant advantages over existing single material solutions. In this paper, PVDF-PA12 for Flexible pipes and EFEP-PA12 for Umbilicals will be introduced in more detail.
How Subsea Constraints Influence Design Choices for Protection Systems
Authors: Hazel Terence , Goulielmakis David , Andrea Pierrick 
Published: June 2014

Abstract
One of the objectives announced by some of the major players in the oil and gas market is placing subsea processing on the sea bed thus eliminating all topsides. Such full-subsea processing plants will be powered and controlled from the shore station and will export extracted products there directly. Due to the long tie-back distances from the shore to the subsea processing plant, it will be necessary to have a subsea power distribution system to supply the loads. It is not economically feasible to supply subsea loads individually from the power source as is done today from platforms or floating structures. Projected subsea processing plants could consume as much as 60 MW. The technology that is commercially available today uses 50 and 60 Hz alternating current (AC) power distribution.
There are many challenges to achieve this goal. One of these is the design of the protection system for the complete power distribution system. Under the term "protection" are the typical overload, over current and earth fault protection functions, but also overvoltage protection. Even though subsea processing plants will be unmanned since they are inaccessible, protection of personnel must still be considered since the subsea equipment is connected to surface equipment.
Due to the difficulty and cost of accessing the subsea equipment for replacement in case of failure, it is very important to know where the fault occurred. Since human intervention at depths where subsea processing will take place is not possible, maintenance personnel must be able to rely on the information from the protection system to know which equipment to retrieve. The protection and fault location of the power umbilical itself is very important due to both the cost and the importance of this asset. Fault location is critical since that is where the cable will be cut for repair, assuming that repair is possible. Positive fault location is a critical design criterion for subsea protection systems.
Another challenge is the distinguishing between load currents and fault currents. The long cable lengths introduce large impedances in the short-circuit current path, especially for the low voltage (LV) modules due to the impedance of their step- down transformers. The protection devices used must be able to positively determine when a fault has occurred and not cause an unwanted trip. LV loads are often subject to modification and it is also a design requirement that the protection settings of LV devices be able to be remotely set. Modifications of protection function requirements should be able to be handled by the reconfiguration of existing devices. The use of the new IEC 61850 standards for "Communication Networks and Systems in Substations" for subsea applications facilitates this since protection signals can be reliably transmitted by the communication system using the fiber optic cables installed for monitoring and remote control.
Practical and Theoretical Assessments of Subsea Installation Capacity for HYSY 201 Laybarge According to Recent Project Performances in South China Sea
Authors: Wang Facheng , Luo Yong , Xie Yi , Li Bin , Li Jiannan 
Published: June 2014

Abstract
As the first deep-water pipe-lay vessel in China, the recently launched Hai Yang Shi You (HYSY) 201 has been designed for up to 3, 000m water depth pipelay and other deepwater subsea equipment installation activities, with its advanced Dynamic Positioning (DP) 2/3 and 4, 000 tons lifting capacity.
After the appearances in several projects in South China Sea (SCS), where water depths ranging from 300m to 1400m, the performance of HYSY 201 has been observed. The excellent project experience has been shared from four perspectives of pipe-lay, lifting, DP system and remote field development requiring multi-function constructions respectively. The performance of integrated pipe-lay and lifting acitivites in one project highlights the economic advantages of the vessel in remote filed developments. The as-built survey results have been employed to provide a quantitative investigation on the final project deliverables by HYSY 201.
The theoretical evaluation of the subsea installation capacity limitation has been carried out by considering both the recorded practical operation data and equipments equipped by the vessel. Based on the analysis and study results, together from the field experience, the limitations of subsea installation capacity have been suggested for HYSY 201.
Ultrahigh Conductivity Umbilicals: Polymer Nanotube Umbilicals
Authors: Dyke C. , Horton H. , Peake D. , Poole J. , Barrera Enrique , Ge Liehui , Biradar Santoshkumar , Boyer Travis , Boyer Luke , Yao Adrian , Lange Eric , Semon Nicholas , Chan David , Vajtai Robert , Ajayan Pulickel 
Published: June 2014

Abstract
This document describes the work performed and scheduled to satisfy the terms of the Research Partnership to Secure Energy for America (RPSEA) contract number 10121-4302-01. NanoRidge Materials, Inc., located in Houston, Texas, is the prime contractor and has subcontracted Rice University and DUCO, Inc. to participate in this endeavor. Representatives from Shell, Baker Hughes, Total, and DUCO, the project's cost share partners, comprise the Steering Committee and Working Project Group. The ultimate goal is to form a power cable umbilical and perform a demonstration for the subsea community. The umbilical, instead of copper, shall have a carbon nanotube cable as the conductor. The difficulties with copper include a) corrosion, particularly at wire terminations, and b) strength, in some applications the weight of copper exceeds its tenacity. The conductor formed in this effort shall overcome these difficulties. The technology under development is the continuous production of CNT wire with in-line post processing steps to form the bare conductor. The resistivity of the carbon nanotube wire shall be equal to copper at one sixth the weight. Once the conductivity is achieved, the wire shall be jacketed with polymer. This material we have termed the polymer nanotube umbilical (PNU®) cable. Since the wire is carbon-based, we anticipate minimal saltwater corrosion. Also, the CNT conductor shall have greater tensile strength than copper. The following is described in this paper:our technical approach and progress,specialty equipment, andPhase I results.
High-Pressure High-Temperature Fluids Modeling: One of the Crucial Keys to Ultra-Deep Gas Drilling
Authors: Seddighin Amir , Krishingee Roxann 
Published: June 2014

AbstractUltra-deep gas reservoirs are becoming a common target in drilling for gas. Unfortunately, most of these reservoirs are highly pressured and extremely hot and have posed a great challenge for the oil and gas industry. Due to the large amounts of hydrocarbon reserves in these areas and growing demands of global energy, operators are investing more time and money into these types of reservoirs.Challenges such as lack of downhole measurement tools in higher temperature and pressure and drilling fluids behavior under HPHT conditions may result in the wellbore stability issues and well control difficulties that put the safety of the personnel and operations in jeopardy.Proper drilling fluids selection and applying the right temperature and hydraulic modeling plays a crucial role in the success of these operations, and helps reduce/mitigate the risk of the operations and non-productive time (NPT). This includes: ECD managements, surge/swab analysis, bit hydraulics optimization, fluid compressibility analysis and all other hydraulics and temperature factors affecting the operations.This paper reviews successful applied modeling and fluids management methods based on proper data gathering and utilizing the best practices results in safe and successful drilling in such hostile environments.
Espirito Santo: Operational Feedback on the Use of Steel Risers on a Turret Moored FPSO
Authors: Newport Andrew , Haheim Svein , Martineau Eric 
Published: June 2014

Abstract
The FPSO Espirito Santo, located offshore Brazil in the Parque das Conchas (BC-10) field, is the world's first turret moored FPSO to use steel risers for fluid transfer. The FPSO is moored in a water depth of 1, 780 meters, and the internal turret incorporates a total of 21 riser and umbilical slots. The steel risers, which are in a Lazy Wave configuration, were pulled into the turret through inclined I-tubes. Clamps at the top of the I-tubes retain the risers, thus transferring axial loads from the risers to the turret. A clamp casting welded at the bottom of the I-tubes houses a stopper arrangement designed to transfer shear forces and moments from the risers to the turret.
The FPSO began oil production in July 2009, and now has over 4 year's optional experience. During this period, inspection of the riser system and the associated flex-joint has confirmed the integrity of the design, giving further confidence in the use of steel risers in turret moored systems.
This paper summarizes the basis for selecting steel risers for the development, how the risers and umbilicals interface with the turret, and the impact of the riser choice on the turret design. The in-service inspection of the riser system is described and the results reported.
Dynamic Simulations of New Well Control Procedures Used to Prepare a Dual Gradient System Field Trial
Authors: Cohen J. H. , Stave R. , Hauge E. , Godhavn J. M. , Molde D. O. 
Published: June 2014

Abstract
This paper reports results on a well control study for a Joint Industry Program (JIP) to develop a Dual Gradient Drilling (DGD) system called Controlled Mud Pressure (CMP). Conventional well control may not be possible when using dual gradient systems, because a choke line full of heavy mud may fracture the formation, thus making well control a major obstacle to implementing DGD offshore. The project developed several well control methods and one was selected for Field Testing, after a risk assessment process with the Operator. The selected procedure is a variation of "Driller's Method". The project also proved that "Partial Dual Gradient Drilling" could be implemented within boundaries of conventional well control, i.e. "Driller's Method" with the DGD system isolated.
A two-phase dual gradient well control simulator was developed for the actual field trial setup. The simulator duplicates planned offshore experiments, including injection of Nitrogen gas "kicks". The simulations show that the DGD system has the capability of detecting formation influxes early, keeping them small so they can be circulated out in dual gradient mode, and the ability of DGD to increase kick margins and thereby improving safety.
This work has application to subsea pump based DGD systems where returns exiting the well are pumped back to the drilling vessel. DGD has application to improve safety and deepen casing shoe depths in deepwater wells.
The simulations show how the system can detect formation influxes or losses, and maintain a safe pressure profile, allowing drilling where conventional principles will not work. They also show how the bottom-hole pressure variations are kept small as influxes are pumped out of a well using a modified driller's method. A planned field trial will verify the simulation results enabling further development of the DGD System.
In many cases, conventional drilling does not permit the economic completion of deep wells in deep-water basins. New technologies need developing to facilitate this drilling. DGD is one technology with significant potential, and has undergone substantial development to allow introduction into these drilling situations.