bluuebunny/crossref_metadata_2025 huggingface dataset:
New Polymeric Materials Development for Extreme Environments
Authors: Drake Kerry , Callaway Ron
Published: June 2014

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

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

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

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

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

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

Ultra-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

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

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.
A Database of Oil Industry Deepwater Current Measurements
Authors: Magnell B.A. , Ivanov L.I. , Szabo D. , Andrews J.B. , Morrison A.T.
Published: June 2014

The paper describes the structure, contents, and data access tools of the database of deepwater current measurements in the Gulf of Mexico developed by Woods Hole Group, Inc. for DeepStar® Deepwater Technology Development Project. Since 2005 the US oil industry has collectively spent tens of millions of dollars to collect ocean current data in the Gulf of Mexico, in accordance with a Government requirement (Notice to Lessees). Twenty-minute ADCP ensemble averages, mainly from rig- or platform-mounted 38kHz ADCPs measuring down to 1000m, are transmitted in real time to the National Data Buoy Center (NDBC). This has resulted in the creation of a massive, multi-year archive of current data in deep areas of the Gulf of Mexico. A DeepStar Project focused on the development of a database of these data.

At present, the database includes 546 quality inspected and edited ADCP current records of BOEM NTL current data, a total of 151.5 instrument-years of ADCP measurements, with associated detailed and accurate (verified) metadata, where each record corresponds to a single, fixed measurement location, and a consistent ADCP setup. In addition it includes 318 ADCP and single-point current meter records of MMS (now BOEM) Environmental Studies Program data. The database provides access to time series plots of current speed and direction profiles for each record in the database, plots of strong current events, as well as data and graphic access tools designed to assist users in locating specific records and plots of the data. This database is the first collection of quality-controlled and edited current data in a form convenient for analysis by oil industry engineers. It is composed of flat files and associated plot and metadata files, each with descriptive file name. Files may be accessed through proprietary map-based GUI or spreadsheet GUI.
Carbon Nanotube Composite Cables for Ultra-Deepwater Oil and Gas Fields
Authors: Holesinger T. G. , DePaula R. , Rowley John , Sperling K. , Pappas J. M.
Published: June 2014

This work summarizes our progress on the development of carbon nanotube (CNT) composite cables for ultra-deepwater oil and gas fields. Near- and long-term intended applications include, for example, more efficient hangar penetrations, sub-sea floor power distribution, and ultra-deepwater dynamic power umbilicals. The project goals are to produce by scalable production methods high-conductivity CNT composite wires that can be wound together to make under sea (and / or in-wellbore) cables. In order to the make practical use of the nanotubes, technologies need to be developed that can deal with or manipulate CNTs in great quantities. For power transmission applications one will need to make dense structures of the CNTs that are aligned simultaneously along the direction of current flow. Also, methodologies that can electrically connect the tubes together in their transverse direction are needed to enable high percolation conductivity though the entire CNT/Metal matrix ensemble. In this work we will summarize our progress towards CNT wire development with descriptions of the wire processing, wire performance, and correlation of performance with structural properties. To date, we have successfully produced wires that display high conductivity values for CNT coatings. Addtionally, these conductors are much lighter compared to pure Cu wires and offer additional advantages for applications needing lightweight materials. Prospects for near and long-term application testing will be discussed.
Microbiologically Influenced Corrosion in Mooring Systems - Field Experience
Authors: Gier Tyler de
Published: June 2014

This paper will compare established theory on Microbiologically Influenced Corrosion (MIC) processes to in-field observations and quantitative measurement, and seek to identify key factors that are involved in the rate of mooring degradation. Early identification is imperative to mitigate risk associated with MIC processes that may cause severe corrosion, such as Sulphate Reducing Bacteria (SRB) corrosion. The first step to identify severe MIC processes is to recognise visual indicators, ideally followed by laboratory testing to confirm. Once the likelihood of adverse MIC is identified, a focussed inspection must be carried out in the locations most likely to be affected. Welaptega's field observations show that variables such as mooring dynamics and water temperature may play key roles.
API 17TR8 - HPHT Design Guideline for Subsea Equipment
Authors: Skeels H. Brian
Published: June 2014

This paper describes the new API guidelines being proposed to establish design methodology, material functional specifications, design validation requirements for equipment designed to operating above 15 000 psi (103.5 MPa) rated working pressure and/or 350°F (177°C) operating temperature through API 17 Technical Report TR8: High Pressure - High Temperature (HPHT) Design Guidelines. The proposed design guideline is intended to provide the wording and the reference information which can be incorporated into any of the subsea hardware specifications, standards and recommended practices within the suite of subsea API (SC 17) documents. Its intent is to be a reference cited in part or in total, by the various API subsea hardware documents, allowing them to expand their working pressure and temperature classifications without having to re-write the relevant sections into their governing documents. API 17TR8 contains detailed guidelines on new design methodology, material property requirements, design validation testing, and special requirements for seals and fasteners when considering the effects of HPHT wellbore fluids passing through subsea equipment.
API RP 2GEN – Establishing Consistency in Design Margins
Authors: Wisch David J
Published: June 2014

The API Series 2 documents cover a wide range of offshore structures. Through evolution and borrowing from different documents, design margins and reliability levels indicate some inconsistency. An API Task Group is developing a strategy providing consistency across the various structures and components covered in the Series 2 Standards. This work will result in a new API standard providing guidance and high level design objectives. This work is parallel to and will feed into the third edition of ISO 19900, the overarching standard for the ISO 19900 Offshore Structures Series.

Areas of discussion will include the background, usage and relative value of the use of a defined air gap, variance between structural factor of safety and mooring factors of safety approaches, the rationale for performance margins that may differ between new and existing facilities, the impact of the slope of the hazard curve and how the slope has created misunderstanding along with other topics critical in the performance of offshore structures.

This paper will detail the results of a comprehensive audit of design practices and conditions in current Series 2 standards and provide a framework for future work providing consistency in margin approach and the logic for assessment of existing facilities relative to that for new facilities. This framework will provide an increased ability for owners and regulators to make conscious choices and have the ability to identify inconsistencies in design targets/margins that can easily occur in today's practice.
A Review of IC Installations: Lessons Learned from Electric-Hydraulic, Hydraulic and All-Electric Systems
Authors: Potiani Maciel , Eduardo Motta
Published: June 2014

The first intelligent completion was achieved in 1997, and since then reliability assurance is regarded as one of the most important themes for market implementation of this technology. Currently, intelligent completion can be found in most global oil and gas production areas, from mature land to ultra-deepwater wells like those in the Pre-Salt region, offshore Brazil. Intelligent completion technology has been applied to improve the return on investment over the life of the field. This is achieved by oil recovery enhancement, consequently increasing net present value (NPV) through selective or comingled production, efficient water or gas sweep, reduced interventions and ultimate reservoir control.

Until recently, almost all intelligent completion installations in the world were fitted with remotely actuated hydraulic systems. However, there are other kinds of systems, such as electric-hydraulic and all-electric systems. The world's first all- electric intelligent completion installation was carried out in Brazil in May 2001, in the land well 8-VRG-7D-RN (Petrobras) in Mossoró (Rio Grande do Norte State) for a trial period ending in April 2002. Following this first onshore installation, a subsea deepwater well installation was carried out in August 2003 in the well 8-MLS-67HA-RJS in a water depth of 1180 m in the MarlimSul field, about 100 Km offshore Campos (Campos Basin), Rio de Janeiro State, Brazil. The installation is still operational until the present day, almost ten years after its deployment. Consequently, it is difficult to understand why the electrical technology is yet to be widely applied around the world, differently from what has already happened in several other industries, like automotive and aviation.

This paper does a brief comparison among hydraulic, electric-hydraulic and all-electric systems, focusing on the advantages of each system. An explanation is offered for the apparent suspicion towards all-electric technology, and a review is made on the prognosis for this system after the first installation in the world5.
Improving Well Integrity in Permanent Downhole Monitoring Systems
Authors: Engel Thomas , Baldwin Chris , Grunbeck John , Kiddy Jason , Stokkeland Kaj
Published: June 2014

Well integrity has become an increasingly important issue for oilfield components. Stricter testing procedures and qualification requirements are becoming more prevalent for primary well fluid containment devices. This is being extended to well monitoring systems, including those permanently installed on well completions using electronic or optical cables. One example is the new fire test requirement for Optical Well Head Outlets (OWHO) per Statoil's document TR3540, Surface wellhead and christmas tree system, with procedures defined in API 6FB: Fire Test for End Connections. Operators are also demanding increased reliability for downhole systems. Ensuring that the seals are properly installed and functional in drymate connectors and pressure foot devices is critical.

This paper discusses the development and qualification of an OWHO that meets API 6FB. Key design issues such as thermal coefficient of expansion differences of materials, seal evaluations, and feed-through issues as related to surviving the extreme temperature conditions of the flame test are discussed. Development and testing of pressure-testable multipin drymate connectors and an improved pressure foot design is also discussed.

Development of highly reliable downhole components requires significant design and testing. For the OWHO, an internal pressure of 11, 250 psi (775.7 bar) was maintained while the wellhead outlet was brought to a temperature that exceeded 900°C (1, 652°F), with the internal feed-through exceeding 650°C (1, 202°F) during the test. The OWHO experienced no leaks at any stage of the qualification testing. The design of the pressure-testable drymate connector and pressure foot has been developed to qualify for infield hydraulic tests.

The OWHO met the harsh environment requirements of TR3540 through a successful flame test carried out in accordance with API 6FB. The newly designed drymate connector and pressure foot provide a reliable, field-testable solution representing a significant step forward to ensuring well integrity.
More Improvements to Deepwater Subsea Measurement
Authors: Shen J. , Pappas J.M. , Letton W.
Published: June 2014

During the last decade there has been an effort to develop new measurement capabilities for ultra-deepwater oil and gas production. Beginning in 2005 and continuing through 2011, R&D was conducted on what were perceived to be the most important gaps in deepwater measurement technology.

The work was initially sponsored by the Deep Star consortium. Beginning at the end of 2008 a larger effort – Improvements to Deepwater Subsea Measurement – was initiated under the Research Partnership to Secure Energy for America (RPSEA). Key to its success was the active support of a JIP sponsored by seven deepwater operating companies: BHP, BP, Chevron, Conoco Phillips, Shell, Statoil, and Total. In 2012 RPSEA approved a Phase 2 effort to extend the results that had been achieved in the first project.

The new project – More Improvements to Deepwater Subsea Measurement – has addressed these five gaps, viewed as the most pressing for multiphase flow measurement by the new JIP (Chevron, Conoco Phillips, GE, Statoil, and Total):Deepwater Fluid SamplingDeepwater Metering TechnologyDownhole Differential Pressure Sensor DevelopmentVirtual Flow Meter EvaluationDetection of Meter Fouling

These technology developments are significant due to the increasing global importance of subsea production. Improved recovery from deepwater reservoirs could yield millions of barrels of additional reserves, but to achieve this goal requires better, more reliable measurement at the sea floor. Equally important is insuring that royalty assessment and production allocation are precise and equitable.

However, a notable application for these new measurement technologies is in the areas of safety and the environment. It should be clear that better, more extensive measurement can be pivotal in preventing the loss of well control and the kinds of events that may ensue. Certain aspects of this new measurement project take dead aim at this goal, as will be explained.

The paper and presentation will provide a look at progress that is being achieved in addressing each of the five gaps listed above.
API RP17W Subsea Capping Stacks
Authors: Sadenwater Daniel
Published: June 2014

Within two years of the Macando incident, approximately 20 different subsea capping stack configurations and designs had been assembled without a guiding reference. Now, API, with input from the Oil& Gas industry, is developing a recommended practice for the design, manufacturing and testing of subsea capping stacks. While subsea capping stacks have remained the preferred concept for capping a subsea blowout, today industry better understands how equipment selection and designs are affected by the operating environment.

There continues to be an immediate need for industry guidance on how subsea capping stacks should be designed and tested for flowing conditions. For this reason, API has focused on developing API RP17W Subsea Capping Stacks with a multi-disciplined team representing over twenty-five operators, service providers, equipment manufacturers, and regulators. This effort has resulted in a technically detailed document covering;system requirements, including interfaces, service conditions, and controls; stack use, including installation points and closure sequences; and stack preservation, maintenance, and testing.
VIM Model Testing and VIM Induced Mooring Fatigue of a Dry Paired-Column Semisubmersible Platform
Authors: Jun Zou , Poll Philip , Antony Arun , Das Suvabrata , Padmanabhan Rajith , Vinayan Vimal , Parambath Ashwin
Published: June 2014

The Paired-Column Semisubmersible (PC Semi) concept was selected as a dry tree alternative for ultra-deep water development by RPSEA in 2009. Since then, RPSEA continuously supported maturation of PC Semi. The PC Semi platform has relatively deeper draft and smaller columns compared to those of a generic Deep Draft Semisubmersible (DD Semi) platform. Due to its larger column slenderness ratio, it might be suspected to have a pronounced VIM response. VIM response characteristics of a floater are the key measures of its performance. It is an essential step to explore VIM response characteristics during concept maturation. An extensive VIM model test program funded by RPSEA was performed at MARIN in June, 2013. Key results are summarized and presented in this paper.

Since the VIM response of a floater (Spar or Semi) is a controlling factor for mooring fatigue, VIM induced mooring fatigue analysis was followed by employing the measured test results. A typical loop current scatter diagram for the GoM was considered and the resultant fatigue damage was analyzed and highlighted. A parallel study for VIM induced mooring fatigue of a generic dry tree DD Semi was also carried out to establish a baseline for comparison of the PC Semi response features and mooring fatigue.
A Comparison of Pre- and Post-2005 Sanctioned Gulf of Mexico Tension Leg, Semi-submersible, and Spar Floating Platforms
Authors: D'Souza Richard , Aggarwal Rajiv , Basu Shiladitya
Published: June 2014

Between 2005 and 2010, three major events led to a significant increase in design demands of deepwater field developments in the Gulf of Mexico (GoM):Category 5 hurricanes Katrina and Rita (2005),The Macondo well blowout (2010), andThe development of deeper, tighter, more remote reservoirs

These events have resulted in increased metocean criteria, new safety regulations and functional requirements associated with producing deeper, higher pressure and lower porosity reservoirs. This paper will examine and contrast the design impacts on Tension Leg Platform (TLP), Semi-submersible and Spar floating platforms before and after these events. The overall impact of these new requirements on topsides, hull, station-keeping and riser systems of recently sanctioned TLP, Semi-submersible and Spar platforms will be compared with pre-2005 sanctioned platform analogues to demonstrate the resulting impacts on platform size and cost.

Increased demands of post-2005 sanctioned GoM floating platforms have resulted in higher deck elevations, greater topsides payload, more robust station-keeping systems and larger hull displacements. Further, the feasibility of proven risers and well systems is challenged by the higher wave induced motions associated with greater design and survival sea-states and high pressure reservoirs. The design impacts of pre- and post-2005 sanctioned TLPs (Mars A, Olympus), Semi-submersibles (Atlantis, Jack St. Malo) and Spars (Tahiti, Lucius) on topsides, hull, station-keeping and riser systems will be compared and differences explained.

This paper will enable Operators and platform designers to:Appreciate the magnitude of impact on size and cost of floating platforms of post-2005 requirements,Understand the relative impacts on the three major hull types commonly used for GoM developments, andUpdate analogues and norms used in benchmarking and concept selection
Olympus TLP – Challenges and Considerations of Designing a Deepwater Venture for a 45 year Production Life
Authors: Fulton David , Johnson Darin , Kamal Rajiv , Kite Mark , Ting Meng-Sing , Lindsey Mark
Published: June 2014

The Olympus Tension Leg Platform has been designed for a 45 year service life, consistent with the depletion plan for this offshore Gulf of Mexico Mars field. This is an increased service life when compared with the design basis of previous Shell Gulf of Mexico TLPs. This criterion manifested itself in several design and physical considerations for the project infrastructure which will be discussed. Key elements of infrastructure reviewed include:TLP StructureTendons and FoundationsTop Tensioned RisersSurface Production Facilities
Vortex Induced VIBRATION Model Test for Step Riser configuration
Authors: Hou Yucheng , Yuan Jiabei , Zhang John , Tan Zhimin
Published: June 2014

Deepwater flexible riser development is often limited by strength and fatigue shortages at the hang off region due to the huge tension induced by the pipe's weight in the deepwater column. A step riser configuration has been developed to reduce these limitations in deep and ultra-deepwater applications. The step riser configuration is comprised of a series of buoyancy cans or modules distributed around the endfitting area to provide a relative large uplift force to compensate for the weight of the flexible riser. Numerical simulations indicate that this step riser configuration is very effective in reducing the tensions at hangoff, thus improving the strength and reducing the fatigue of the flexible riser.

The vortex induced vibration (VIV) in the step riser configuration needs to be closely monitored since the deepwater depth and relative large OD of the buoyancy cans or modules will result in greater current loads exerted on the pipe, increasing the drag area.

A 1:40 ratio model test has been performed to investigate the excitation of VIV to the step riser configuration. The test section was composed of flexible riser, buoyancy cans, endfitting and its vicinity area. Strain gauges and optical fibers were used to measure the deformation of the flexible pipe and joint mechanism of the step riser configuration. Real time strain signals were collected and post-processed into the frequency domain. System lock-in phenomena was observed during the model test.

The intensity of VIV excitation in the model test for normal current ranges in deep waters will be described. Based on the model test, the VIV vibration amplitude in both flow and perpendicular flow directions will be summarized and discussed. The VIV frequency and energy spectrum will also be presented and discussed in this paper.
Will Unconventional Play Revolution Impact Deepwater Development?
Authors: Chin Doreen , Khurana Sandeep
Published: June 2014

Preface

This manuscript is intended to set the stage for a panel discussion, "Will Unconventional Play Revolution Impact Deepwater Development?" scheduled for Monday, May 5, 2014. The manuscript includes input from participants of this panel, who are:

Panelists:

Torstein Hole/Statoil – SVP Development and Production US Onshore Greg Guidry/Shell – EVP Upstream Americas Unconventionals Lee M. Tillman/Marathon Oil Corporation – President and CEO Darrell Hollek/Anadarko – SVP Deepwater Americas Operations and Development David Eyton/BP – Group Head of Technology James A. Slutz/Global Energy Strategies LLC – President

Moderators:

Doreen Chin/Shell – Surface Advisor, Upstream Unconventional. Chair for OTC 2014 Program Committee Sandeep Khurana/Noble Energy, Inc. – Manager Development Planning

The recent surge in unconventional oil and natural gas production in the United States (US) has been called a "Revolution". Unlocking of massive unconventional reserves in the US is the biggest game changer in recent years. The US is now the number one unconventional oil and gas producer in the world. US together with Canada now accounts for more than twenty-five percent (25%) of global natural gas production. Shale gas will play an ever-increasing role in this resource base and per Energy Information Administration (EIA) is projected to increase to almost half of total US gas production by 2040. Per EIA, US tight oil production will continue to grow till 2020 and is projected to reach almost half of total US oil production. Influenced by the US success, the global unconventional play exploration activities have been active and also increased. This revolution has re-shaped and will continue to shape the energy resource picture for the entire world. For instance, in the US unconventional play investment has also led to resurgence of domestic manufacturing. Though onshore unconventional play development has very different development style (faster pace, cost sensitive, high number of well count, urban planning, etc.) from deepwater development (much higher cost and related risks, fewer wells, long project time, technology intensive, etc.), they have started and will continuously compete in talent recourses, investment flow, and technology supplies, etc. This manuscript discusses supply projections and overlays it with market drivers to portray value proposition. It compares and contrasts unconventional plays and deepwater from a full life cycle of exploration to operations. It discusses implication of regulations and policy. It then summarizes and identifies areas of discussion and viewpoints from panelists.
Funding New E&P Technologies
Authors: Schroeder Art J.
Published: June 2014

OTC Panel Session; Funding New E&P Technologies: At the end of the day, new technology is only valuable if it can be successfully deployed; and this of course requires operator up-take or ‘pull’. While operators and established service and manufacturing companies supply the bulk of new E&P technology, a number of different organizations provide alternative funding mechanisms. This panel session will examine six (6) ‘funding’ organizations. The presentations and moderated discussion will cover:–Present / current funding solicitation and evaluation process–Future technology needs and expected funding levels over the next ~ 3 years–How these needs and levels may have changed from the recent past–The good, bad and ugly of past solicitations; what do prospective awardees need to do well in the solicitation process to be in the best position to secure funding.–Lessons learned from previously funded and executed R&D projects with examples of projects or seed funding that resulted in commercial success or failure–Advice and guidance to ‘budding entrepreneurs’ and start-up companies

Session Moderators: Opening introduction and scene settingBrad Burke, Managing Director; Rice Alliance for Technology and EntrepreneurshipArt Schroeder, CEO; Energy Valley, Inc.

Panelist:DeepStar – Greg Kusinski, DeepStar Director and Senior Advisor from ChevronITF – Paddy O'Brien; CEOResearch & Development Corporation – Glenn Janes, CEORPSEA – James Pappas, VP Ultra-DeepwaterEnergy Ventures – Jim Sledzik, Partner and President, Houston OfficeStatoil Technology Invest – Richard Erskine; Investment Manager

Each panelist will utilize about 10 minutes to cover their organization's basic mission and parameters of operation, followed with approximately 1 hour of moderated panel discussion.
Model Based Multiphase Metering and Production Allocation
Authors: Patel Piyush , Odden Havard , Djoric Biljana , Garner Robert Dennis , Vea Hans Kristian
Published: June 2014

It is irrefutable that subsea operation is one of the most critical operations for Oil & Gas industry. To meet the growing demand of energy in the coming years, upstream oil and gas industry will develop even marginal fields which would tie-back to existing infrastructure and require more complex subsea network. Subsea production monitoring, back allocation and fiscal allocation are an essential part of any field development, as inaccurate tracking of production will negatively impact management and recovery from a reservoir. The need for allocation is due to the fact of unavailable quality measurements of oil, gas, condensate and water produced and injected at all nodes in a subsea distribution system.

Contrary to easily monitored downstream onshore operation, subsea offshore operations cannot be easily monitored due to low reliability and high cost of subsea sensors. From industry experience, the currently available physical subsea flow meters, instrumentation and associated measurements are subject to deficiency, inconsistency and failure and results in low accuracy, and reliability. Due to these facts, there is a high demand for an alternative and accurate method of flow metering and condition monitoring for offshore operation and processing.

In the past few years the use of Virtual Flow Metering systems as a backup or validation system for MPFMs or Wet Gas Meters has become more common. There are various options available depending on the vendor; statistical analysis of measurements (steady state solution), high fidelity online flow simulation models (dynamic solution) or a mix of both (nodal analysis). While VFM is maturing it has not been fully accepted as a viable alternative to good physical metering.

Driving the dynamic model with real time measurements from the plant opens a new world of information for the operator in terms of model estimated data and enables him to take better decisions.

This paper will present a case study whereby a virtual flow metering system has fully replaced a multiphase flow meter for flow metering and allocation purposes.