bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsea Sampling and Sensor Insertion Systems for Improved Accuracy of Production Measurement
Authors: Kelner E. , Toskey E.D. , Crider J. 
Published: April 2015

Abstract
The increase in deepwater field development in the Gulf of Mexico and other locations has brought an increase in the use of subsea multiphase flow meters (MPFMs) for individual well flow rate monitoring at or near the wellhead. Their justification usually is to obtain improved well and reservoir management, or a more verifiable allocation of production between wells, such as where the ownership or royalty rate differs amongst the wells producing to the same platform. The two most common inadequacies of subsea MPFM installations has been the insufficiency with which one can characterize the produced fluids – for measurement accuracy, and the unavailability of any supplemental measurements, even if only temporary – for measurement verification. Without these, MPFM measurements can be inaccurate, and there may be no means to verify them. Unverifiable and questionable measurements will likely go unused, and the value originally sought with the installation of the MPFM goes out of reach.
Although experience with MPFMs on land and topsides, where they are accessible, has demonstrated the importance of characterizing the fluid properties from analyzed fluid samples, and having alternative means to measure flow to validate the MPFMs, subsea multiphase meter installations rarely have any facility for fluid sampling or supplemental measurement. Until recently, the development of sampling techniques has been limited and there have been no systems developed which could deploy a variety of other sensors near the MPFM for the purposes of verification. For subsea MPFMs to fulfill their original purpose of providing long-term reliable subsea wellhead measurement, MPFM installations need to have the facilities for subsea fluid sampling and subsea sensor insertion/removal, which would provide timely and accurate fluid properties at meter conditions, and a means to verify MPFM performance. Topside well tests and samples of commingled well streams cannot meet these needs.
This paper describes two technology developments which address these issues: 1) a remotely operated underwater vehicle (ROV) deployed subsea sampling system, which provides a means to capture fluid samples for the purposes of fluid property determination at the multiphase meter or other locations at any time in the life of the well, and 2) an ROV-operated subsea sensor installation/removal system that enables the placement of a variety of sensors in direct contact with process fluids, and extends the flexibility and range of subsea wellhead and subsea process measurement.
Fatigue Damage to Circumferential Weldments and Mitigation Techniques
Authors: D.A. Nowak , G. Slater 
Published: April 2015

Abstract
The paper focuses on the results of full size conductor connector-to-pipe fatigue testing of circumferential weldments, and mitigation techniques to inhibit fatigue failure and to evaluate the level of component life extension. This study utilized a standard conductor connector welded to 559 mm (22 inch) diameter by 25 mm (1 inch) wall thickness X56 line pipe. Resonance fatigue testing was carried out at TWI Limited in Cambridge, England. Standard manufacturing tolerances for pipe ovality, weld joint mismatch, and ‘flush’ blending of the weld profiles on both the internal and external surfaces were used for each of the fabricated fatigue specimens. All tests specimens were Phased-Array Ultrasonically Tested (PAUT) both before and after fatigue testing, and were run with a relatively low axial mean stress of 10 MPa (1.45 ksi) created by internal water pressure. Results showed at the lower cyclic stress range, 100 MPa (14.5 ksi), that most of the fatigue failures were outside of the connectors, while all of the higher cyclic stress range tests, 150 MPa (21.75 ksi), failed in the conductor connector. A second phase of testing eliminated the stress concentrations from the conductor connector design and welded the connector profile halves together. All phase 2 tests were performed at the higher cyclic stress range, and failed in the X56 piping. Three of the phase 2 tests incorporated mechanical shot peening over the blended internal and external weld surfaces to improve fatigue resistance. All three of these tests also failed in the X56 line pipe material, well outside of the weld area.
A New Process for the Management and Delivery of IMMR and Geoscience Data Which Enables Management, Interpretation and Delivery of Extremely High Resolution Data on Any Computer
Authors: Sean Halpin , Taylor Brown 
Published: April 2015

Abstract
Significant advances have been made in the past decades in spatial data management by GIS defense contractors that allow clients to rapidly process, store, and recall large swaths of sub-decimeter resolution imagery generated by satellites, manned aerial surveys, and drones. In onshore oil and gas, similar GIS technology is being adopted to manage assets, logistics, and UAV-surveyed pipeline inspection data, including 3D mapping, change detection, and leak detection data. Adoption of such enterprise grade GIS solutions for survey data along the life of a pipeline, however, has been much slower offshore.
Through adopting this defense-grade technology, the full capacity of using GIS as the complete IMMR tool is realized. Pre-lay, as-built, and inspection survey data are able to be managed and rapidly recalled at full, as-surveyed centimeter resolution in a GIS environment. In this manuscript we present a comparison of conventional technology and a new novel custom software package during analysis of a 11,294 km fictitious pipeline originating in Houston, TX and terminating in Alaska. Data refresh rates are dramatically better (on average 7 times better) when working with the data and the data may be served to a variety of applications including a common web browser and many common platforms outside of the Oil and Gas industry. This software allows contractors to generate data products at the resolution of the sensor and allows Oil and Gas clients to move their data from the box in the corner to live and recallable platforms.
Local content, the driving force on the CLOV Project
Authors: François Bichon , Antonio Cardoso 
Published: April 2015

Abstract
Local content was fundamental to Total E&P Angola's development philosophy for the CLOV mega-project, offshore Angola. The aim - to allow CLOV to provide with a lasting legacy in terms of human and facilities resources - was to achieve 10 million man-hours of local activity in Angola at first oil - a tenfold increase from Total's first deepwater development at Girassol - and the fabrication of 64,000 tonnes of structures in five domestic construction yards.
Based on Total E&P Angola's policy of sustainable development, a plan was devised and executed that included specific health, safety, environmental and quality requirements and ethical standards, all in accordance with Angola's socio-economic and cultural characteristics.
Local content challenges were identified at early stage of the project. It allowed the development of a sound strategy based on selection, management and execution. This resulted in the upgrades of three of the five fabrication yards which were implemented in a cost-effective and timely fashion to meet overall project cost and schedules.
It was of paramount importance that if these yards were to perform essential work, they had to be manned with a skilled local workforce. Therefore, training was another key area of development for both the project team and contractors.
Technical Challenges and Impacts of Extending Spar and Semisubmersible Platform Capabilities to 4,500 m Water Depth
Authors: D'Souza R. B. , Aggarwal R. , Subramanian R. 
Published: April 2015

Spar and semi-submersible platforms are proven deepwater production platforms. They have been used extensively in the Gulf of Mexico (GoM) to produce large deepwater developments. Spars have progressed from 600 m to 2,600 m water depth since 1995 and semi-submersibles from 450 m to 2,500 m since 1985. Topsides and hull sizes have grown to accommodate increasingly larger topside, riser, and mooring payloads. Extending these platforms to 4,500 m represents an almost 80% increase in water depth. The main technical challenges relate to the technical feasibility and installation of risers and mooring systems and their impact on the size and global performance of the hulls. Both aspects are examined in this paper for applications in the GoM.
The first aspect addresses technical challenges associated with designing production, injection, and export risers to handle the large hydrostatic pressure and limitations and/or gaps with regard to current lay vessel capabilities to install risers in 4,500 m water depths. The second aspect addresses the relative sensitivity of hull sizes and global performance of semi-subs and spars at these water depths for a common topsides and subsea architecture basis of design.
This paper presents the impact of extending design, fabrication, and installation of spar and semi-sub floating platforms to 4,500 m water depth. Field development scenarios, design basis and topside parameters (load, area, and height) are used to size hull, mooring, and risers to define the overall system. Proven, conventional hull designs and sub-systems technologies are used for both 2,500 m and 4,500 m water depths. Platform sizes and global responses in 2,500 m and 4,500 m water depths are compared. Technology gaps in meeting basis of design are identified. Trends, observations and relative sensitivities of the hull forms are captured. Enhancing and enabling technologies for risers and moorings are discussed. The 4,500 m hull sizes and key dimensions are compared with existing platforms to address availability of yards and vessels for construction and installation phases. Challenges related to fabrication, topside integration, mooring and risers installation in 4,500 m water depth for the two hull types are also addressed and contrasted.
VIM Study for Deep Draft Column Stabilized Floaters
Authors: Antony A. , Vinayan V. , Holmes S. , Spernjak D. , Kim S. J. , Halkyard J. 
Published: April 2015

Abstract
Dry-tree semisubmersible concepts have been studied under multiple RPSEA funded projects since 2009. As hull forms used for dry tree applications have a deeper draft, vortex induced motion (VIM) can be an area of concern that needs to be addressed during design stage. The VIM model testing that was conducted during prior RPSEA study phases indicated that VIM exists and can impact the platform mooring and riser integrity. The current RPSEA funded project is aimed at improving overall mooring system safety and riser system integrity by testing design parameters of deep draft column stabilized floaters (DDCSF) to determine the ones that have the most impact on VIM.
The study utilizes computational fluid dynamics (CFD) analysis and model testing to determine the sensitivity of VIM responses to DDCSF geometric parameters. The project studies both a four-column DDCSF and a multi-column DDCSF, specifically, the paired-column DDCSF developed by Houston Offshore Engineering (HOE). The CFD tools used are AcuSolve™ from Altair Engineering, Fluent™ from ANSYS and STAR-CCM+™ from CD-adapco. In this study existing VIM model test data is used to validate/verify the CFD tools, and the results are discussed in the paper. Some observations from the validation study are also discussed in the paper. More VIM model tests will be conducted during the later phase of the ongoing RPSEA project to correlate the CFD predictions with experimental data.
The study results are part of "Vortex Induced Motion Study for Deep Draft Column Stabilized Floaters", a study funded by Research Partnership to Secure Energy for America (RPSEA), under the project number 11121-5404-03.
Execution Challenges for a First of its Kind Project in Santos Basin Brazil
Authors: Camozzato Guilherme , Poirier Nicolas , Hiller Daniel , Acheritobehere Alain , Xavier Marcelo , Romeu Nelson Bittar , Seize Esio , Silva Alex Limeira 
Published: April 2015

Abstract
Sapinhoá-Lula NE project is a major subsea EPCI project where the successful introduction of innovative state-of-the-art technology was undertaken on a fast track schedule. The project execution included integrated supply chain and complex operations coordination with offshore campaigns performed in an extreme ultra-deep water environment where conditions are challenging. Awarded at the beginning of 2011, the Sapinhoá-Lula NE project was the first billion dollar subsea installation project ever in Brazil. The objective of this paper is to describe Sapinhoá-Lula NE project execution through its various phases and challenges from its award to its delivery.
The project had a number of technical challenges that were well understood and anticpated from the very start. Of significant importance was the need to design and fabricate four Buoy Supporting Risers (BSRs). Other technical considerations included component engineering, the mooring and monitoring of systems for the buoys and lay for the first lined pipe reeled under pressure.
Additionally, the Sapinhoá-Lula NE project team needed to have safety as its early focus on people, equipment and the environment. A commitment to innovation was of key importance with a significant number of new technologies, equipment and installation procedures needing to be developed, qualified, fabricated, tested and installed. The highest standards of quality and team collaboration at a global level were required in order to allow lessons learnt of each new operation to be promptly analyzed and implemented. Integrity at all levels and times, commitment to contract obligations and Client expectations were kept, regardless of the challenges faced.
As a result, within three years of contract award, Client had its first oil on the largest subsea EPIC signed to that date in Brazil. After four years of contract award, offshore execution was concluded delivering more than 30, 000 ton of state of the art equipment, installed in two fields, 300 km away from Brazilian southeast coast and producing 240, 000 bbl/day.
Design and Development of an HPHT Drillstem Testing Valve: A Case Study in HPHT Tool Design
Authors: Stolboushkin Eugene , Zuklic Steve , Fuxa Jason 
Published: April 2015

Abstract
The past several decades have shown a steady trend of work performed in increasing well temperatures and pressures; however, the industry has been slow to adopt new methods in the design of equipment to be used for these wells. As a result, certain types of equipment are now insufficient for operations in high-pressure, high-temperature (HPHT) wells. This hinders the development of HPHT fields and reduces the ultimate recovery from those fields; technologies that are successfully used in conventional wells are only very reluctantly used in HPHT wells.
Drillstem Testing (DST) valves are used for DST work, but also for tubing-conveyed-perforating (TCP) "shoot and pull" operations. These valves enable under- and over-balanced perforating, increasing the perforation quality and minimize the formation damage caused by kill fluids. However, these types of valves are frequently perceived as insufficiently reliable for TCP operations in HPHT wells, and frequently simpler perforation jobs are performed, sacrificing perforation performance for reliability.
A new DST Combined Test tool was designed with advanced analysis methods. These methods include not just stress and deflection analysis, but also an analysis of historic failure modes, including human factors, and the implementation of mechanical fail safes to prevent them in the new valve. The valve was tested to 30,000 psi hydrostatic with tubing pressure in excess of 40,000 psi, and at 400°F. Finally, the valve has been successfully deployed on field trials. This paper will present an overview of the valve development as a case study for the development of future HPHT tools.
Should Aluminum Conductors be Considered for my Subsea Power Cable Application?
Authors: Voight R. 
Published: April 2015

Abstract
Most baby-boomers have some familiarity with the classical stigma surrounding aluminum conductors in residential and commercial applications: fire hazard. Mention aluminum wiring in a building or residence and, not surprisingly, a lot of folks will react as if the structure in question should be condemned. How did aluminum get this reputation? Was it deserved? Is it still a valid assumption with today's modern aluminum alloys?
Many of the historical stigmas associated with aluminum can be attributed to technical design problems of the older alloys that have now been overcome by higher quality materials and/or addressed by aluminum specific design considerations. This paper addresses the aforementioned issues and investigates the current status of aluminum conductor technology as applied to subsea power cables with a specific emphasis on the following:
The Element Aluminum; Early History of Aluminum; Historical Stigmas; Technical Advances; Aluminum (Al) versus Copper (Cu); Aluminum Subsea Cable Experience.
Lucius and Hadrian South Projects: Development Overview
Authors: Lamey M. , Gayneaux J. , Hart D.D. , Arthur T. 
Published: April 2015

Abstract
This paper provides an overview of the development of Anadarko's Lucius oil field and ExxonMobil's Hadrian South natural gas field tie back to the Lucius facility. These projects were successfully completed in 1Q 2015 in the southeast corner of the Keathley Canyon area of the deep water Gulf of Mexico. The Lucius project team responded to the opportunity created by the Hadrian South resource and other challenges resulting from the use of new build vessels, a strained labor market, and new regulations affecting the Gulf of Mexico since 2011. The ability of the project to execute in roughly three years from sanction and only five years from discovery can be credited in large part to the operator's development strategy of utilizing a core group of proven, trusted suppliers. To mitigate site terrain challenges, simplify riser design, and minimize cost/schedule risk, the operator chose a truss spar as the hull for this wet tree only development. It is the operator's largest spar to date.
The Hadrian South project is ExxonMobil's deepest sub-sea tie-back. It was contracted on a competitively bid basis and executed in parallel with the Lucius development. Close cooperation with the Lucius project team, disciplined management of change, and rigorous opportunity and vulnerability tracking resulted in a capital efficient project with a number of scope optimizations and minimal EPC changes.
The Lucius field is located in Keathley Canyon blocks 874, 875, 918, and 919. It holds an estimated 300-plus million recoverable barrels of oil equivalent. This project was sanctioned in December 2011, and achieved first production in January 2015, with the first production from the nearby South Hadrian field in March 2015. The truss spar's topsides process systems can process more than 80,000 BOPD and 450 MMSCFD. The reserves will be produced through six initial wet-tree wells. The Hadrian South field, located in Keathley Canyon block 964, was discovered in 2009, and was sanctioned in December 2011. Hadrian South was developed as a two wet-tree well 300 MMSCFD tieback to the Lucius spar located eight miles to the north/northwest.
Repair and Intervention of HPHT Flowlines
Authors: R. Ayers Ray , A. Wilson Ian , N. Gage Eric , Rebello Armando 
Published: April 2015

The objective of this paper is to report progress and recent findings related to the remediation of damaged high-pressure, high-temperature (HPHT) flowlines in deep water. The flowline repair technology currently being developed utilizes an R&D process of systematically identifying technical gaps, and then developing methods to close those gaps.
While defects or damage to deep-water export pipelines and flowlines is a relatively rare, low-occurrence/high-consequence event, recently compiled information shows that flowline problems involving paraffin or hydrate plugs are more frequent than previously believed. In addition, removing these plugs is complex and difficult.
In 2014, thirteen paraffin plugs and four hydrate plugs occurred in the GOM and are keeping the affected lines out of service. In contrast, only a few flowline repairs are called for each year.
This paper builds in part on prior work by the authors described in OTC 23143 [2], which revealed that the traditional elastomer packer seals used for non HPHT pipeline repair tools will extrude out of the packer cavity and leak when exposed to HPHT conditions that are common to thermally insulated flowlines, rather than uninsulated export pipelines. As a result, sealing system designs must utilize significantly improved sealing methods replacing elastomer packers with diecast graphite packers used for traditional offshore pipeline seal systems.
This paper describes the critical technical gaps identified and closed while conducting a joint industry program for a group of major international operators: (1) removal of wet insulation, (2) development of HPHT sealing systems and (3) development of a subsea coiled tubing insertion hot tap system. The unique approach to developing the technical solutions to these technical gaps involved physical testing of the proposed solutions with test jigs to demonstrate their functionality.
SS-Space Technologies for the Offshore Deepwater Industry: Robotic Solutions for Exploration, Earth and Space
Authors: Ambrose Robert O. 
Published: April 2015

Abstract

Objectives/Scope
This paper describes the challenges NASA sees in space exploration, highlighting several of the robotics solutions now being developed and tested. Overlaps with terrestrial exploration challenges will be noted as potential areas of collaboration. Results from a specific and ongoing collaboration will be described, showing a robot built for exploring tanks on the sea floor with access through existing pipes.

Methods, Procedures, Process
NASA has developed a roadmap for robotics and autonomous systems, as a part of a larger road mapping process for all space technologies. Roadmaps study future missions to identify where new technologies could reduce costs, shorten schedules or enable completely new approaches. These roadmaps are periodically updated by NASA, and the most recently released version will be presented for robotics and autonomous systems.

Results, Observations, Conclusions
Once technologies are identified as needed to support missions, NASA uses technology projects to develop and then test prototypes in labs, test facilities and/or in space. The design and development cycle will be presented for a mix of such efforts, including delivery of robots to space for testing.

Novel/Additive Information
NASA's challenges include operating in extreme pressures, temperatures and radiation. Our missions also take humans and their machines far from Earth, where the speed of light induces time delays for control. NASA has pioneered new techniques for controlling robots in these harsh environments and across time delay with limited bandwidth. These techniques will be described with relevance for the offshore oil and gas industry.
Development and Execution of a Wax Remediation Pigging Program for a Subsea Oil Export Pipeline
Authors: Stevenson Colin J , Davies Simon R , Gasanov Ilgar , Hawkins Paul , Demiroglu Muge , Marwood Andy P 
Published: April 2015

Abstract
We show how state-of-the-art wax deposition modelling can provide an accurate estimate of the location, shape and volume of wax deposits which is key information for the development of a pigging program and the design of the pigs. We show how pigs can be designed to controllably and progressively remove targeted volumes of wax starting from 50% of pipeline diameter while maintaining drive through another 130 kilometers of relatively clean pipeline. Finally, we demonstrate how instrument packages in pigs can be useful in locating and quantifying pipeline restrictions and in providing important data for validating flow assurance models.