bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bounded Opportunity: A Knowledge-Based Approach to Opportunity Recognition and Development
Authors: de Bruin Anne M. , Ferrante Francesco M. 
Published: October 2011

Abstract
This article is premised on the underlying notion that knowledge is crucial to the opportunity recognition and development process. Springboarding from the insights of Atkinson and Stiglitz (1969) on the localized nature of knowledge accumulation, we define a feasible solution space and examine the implications of entrepreneurial knowledge in the recognition and development of opportunity within this space. Distinguishing between two forms of entrepreneurial knowledge, namely context dependent idiosyncratic knowledge or tacit knowledge, and codified knowledge, the primary aim of this article is to propose a knowledge-based model of opportunity within a bounded solution space. Our discussion of this model includes elaboration on how the composition of entrepreneurial knowledge predicts major path differences for the expansion and development of opportunities.
Development of In-Line PLETs for Tupi Pilot Project:Challenges and Lessons Learned
Authors: Mota Helena 
Published: October 2011

Abstract
NOTE: The TUPI field name has changed to LULA field; therefore hereafter we will refer to it by the current name LULA.
This paper will describe the challenges, experience and lessons learned on the development of the In-Line PLETs, for the Lula Pilot Project. The project used the first of its kind In-Line PLET and installation methodologies for Brazil's record ultra-deepwater field Lula. The Lula Pilot Gas Export Pipeline is an 18?? diameter×218 Km Pipeline connecting FPSO Cidade de Angra dos Reis to Mexilhão Platform (PMXL-1). The subsea equipment used on the project were the following: Deepwater PLEM, In-Line PLET, In-Line Wye, Shallow Water PLEM and Jumper Connectors.
There were many new challenges on the project. The first was to design an In-Line PLET and In-Line Wye that were small enough to fit inside the tensioner of an S-lay vessel and strong enough to withstand the installation loads of Lula's 2145 meters water depth. The In-Line PLET and In-Line Wye both have identical configurations that consist of Stress Joints, Pipe-in-Pipe Joints, Swivels, Wye, Ball Valve and Tie-in Hub. But the In-Line PLET's Wye straight brach leg was designed into a Dead Leg to be used as an anchor point to tie-in the additional 320 feet of pipe and laying head needed to set down the In-Line PLET. Addition items included Pipe-in-Pipe Joints, Stress Joints and Swivel. These were used to reduce the stress on the pipeline and equipment during installation.
Another challenge was coordinating the project with the customer and the installation contractor. In addition to the multiple customers, there were multiple manufacturing sites for the equipment, including Houston, Aberdeen, Milan, Paris, Victoria, and Rio.
Design Qualification Testing was completed on the 18?? Intergal Collet Connector and a 10?? Annular MCV Connector. The 18?? Collet Connector was used to tie-in the rigid jumper and the 10?? Annular MCV Connector was used for the Flexible Jumper tie-in. Finally, this paper will describe the successful deployment and installation of the In-Line PLETs, which helped to launch Brazil's record setting Pre-Salt Discovery Lula.

Introduction
A well know subsea layout for Pipeline termination is the use of PLETs connected by Rigid Jumpers to PLEMs. PLEMs can be placed anywhere along the pipeline to allow a future connection to the main Pipeline. An alternative to avoid PLEMs in the middle of the Pipeline and therefore reduce the installation time is the use of a system that can be welded to the Pipeline and deployed in line with the Pipeline, or, In-line systems.
Environmentally-Improved Method of Drilling Top-Hole Sections Offshore Brasil Using Dual-Gradient Drilling Techniques for the First Time in Brasil
Authors: Scanlon Terry 
Published: October 2011

Abstract
This paper describes the design and use of a subsea pumping system that allows improved construction of top-hole sections on offshore, jack up-drilled wells. This system has now been used for the first time offshore Brazil with positive results.
This subsea pumping system - the RMR® (Riserless Mud Recovery) system - has been used extensively in other areas of the world, primarily on floater-drilled wells (Stave et al., 2005; Smith et al., 2010; Cohen et al., 2010). This previous RMR experience coupled with detailed discussions with a Major Operator in Brasil resulted in this modified design for use on jack up-drilled wells, offshore Brasil.
The Major Operator has a number of wells to drill in shallow waters offshore Brasil and needs a system that provides for minimal discharge of cuttings and drilling fluids to the ocean environment during drilling and installation of the conductor string, and that also enables better management of well bore pressures when drilling the next hole section, inside the conductor string.
This new version of the RMR system has now been deployed offshore Brasil. The system collected drilling fluids from the top hole section and pumped them back to the rig successfully, thus reducing the amount of cuttings and drilling fluids released into the natural ocean environment. The system was then used, after installation of the conductor string, to provide dual gradient drilling of the next hole section (for surface casing), resulting in improved penetration rates and well bore stability below the conductor shoe.
The RMR system used is described in this paper as well as the operational experiences realized on the first two wells and the improvements being made to prepare the RMR system and techniques for additional wells.

Introduction
Use of the RMR subsea pumping system is now well-established, particularly for floater-drilled wells, in several parts of the world, namely; Norway, UK, Caspian and Australia. Although well parameters, rig configurations and water depths differ, the typical RMR system used across these operating regions is shown in Figure 1.
Along-String Pressure Evaluation Enabled by Broadband Networked Drillstring Provide Safety, Efficiency Gains
Authors: Veeningen Daan M. 
Published: October 2011

Abstract
The combination of high rig rates, complex reservoirs, and extended reach wellbores drilled in deeper water is placing greater burden on drillers as they attempt to meet the world's growing energy demands in a safe and sustainable manner. Answering the need for faster and more accurate decision-making while drilling, wired-pipe or networked drillstring telemetry has given drillers real-time access to high-definition downhole data such as wellbore images, formation pressure tests and high-frequency pressure and vibration measurements. What's more, the technology transmits this data and sends commands to downhole tools at high resolution and speeds that are more than three orders of magnitude higher than the dozens of bits per second afforded by mud-pulse telemetry methods.
This paper describes the components of the networked drillstring telemetry technology, its theory of operation and the safety and cost efficiency gains it can provide to a drilling operation. The broadband speed aids with mitigation of vibration in real time, to increase the rate of penetration and reduce the number of bit trips. The network nodes offer the unique opportunity to make additional pressure measurements distributed along the entire length of the drillstring. The system's additional dynamic insights also help to manage constant bottomhole pressure as well as drilling at or under balance. Finally, the paper provides examples showing how the system's along-string pressure evaluation capabilities help to identify and locate a pipe wash-out, detect a pack-off, detect the early kicks associated with a wellbore influx and verify that the reamer arms are opened.

Introduction
Today's oil and gas exploration efforts are characterized by high rig rates, complex reservoirs, and extended reach wellbores drilled in deeper water. These complex challenges are complicating driller's efforts to meet the world's growing energy demands in a safe and sustainable manner. To mitigate these challenges, tools to facilitate faster and more accurate decision-making while drilling are required.
The Mass Balance Technique of Managed Pressure Drilling, Reaching the Drilling Objectives Safely and Successfully Beyond the Conventional Limits of HPHT Deepwater Wells.
Authors: Arnone Maurizio Antonio , Hannegan Don M. , Pena Cesar , Piedade Sandro 
Published: October 2011

Abstract
Managed Pressure Drilling (MPD) is an advanced form of primary well control usually employing a closed and pressurizable circulating drilling fluids (mud) system which facilitates drilling with precise management of the wellbore pressure profile. The primary objective of MPD is to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards and to enable the drilling of otherwise technically or economically un-drillable high-complexity prospects.
Because MPD addresses NPT, the technology is of greatest potential benefit to offshore drilling programs where cost of dealing with drilling trouble zones is much higher than onshore. Although MPD was been safely and efficiently practiced from all types of offshore rigs and producing the desired results in the process, it is still considered a relatively "new" technology to the majority of offshore drillers.
This impressive uptake in offshore MPD applications is due in part to a requirement to drill in greater water depths, through depleted zones or reservoirs and into narrow or relatively unknown equivalent mud weight (EMW) drilling windows.
As evidenced by the greatly increased cost of drilling today's prospects, pre-salt drilling in deep water and HT/HP wells being good examples, it is easy to understand why many are concluding that most of the "easy" prospects have already been drilled. Those remaining are more likely to be "hydraulically challenged," requiring more precisely controlled management of the wellbore pressure profile to be drilled safely and efficiently.
The following paper will explain interesting and important MPD topics related with the experience on:–Challenges associated with heaving from a micro-flux perspective, substantiated by high precision pressure sensors.–Kick/loss detection under heaving conditions detecting gains/losses within a micro-influx perspective.–Tactics to improve MPD operations in deepwater environments by the automation choke actuation systems and associated control algorithms.–Tactics for Safeguarding the Riser during MPD Operations.–Tactics for ascertaining the effectiveness of drilling with statically underbalanced mud to reduce/eliminate losses and maintain wellbore stability.
Mooring Chain Handling & Tensioning System for FPSO
Authors: Wudtke Donald J. 
Published: October 2011

Abstract
A mooring chain handling and tensioning system has been developed as an alternatative to the other on-vessel mooring equipment for the FPSO (Floating Production Storage Offloading) type vessels. The mooring chain handler is intended for use on any vessel that is anchored with a pre-laid spread mooring system. A comparable vertical windlass type mooring system and a chain jack type mooring system are also reviewed.
The mooring chain handler can accommodate any deck location, requires only one chain locker and can accommodate all turndown sheaves. A vertical windlass compromises the location of the single windlass to accommodate the additional chain lockers and locations of the turndown sheaves Chain jacks are limited by the intermittent pull and also require additional vertical shaft guide sheaves. The mooring chain handler does not require additional guide sheaves and has uninterrupted power-in power-out unlimited variable speed.
The mooring chain handling & tensioning system requires only two (2) chain handlers and four (4) moveable turndown sheaves to handle up to twenty (20) mooring lines per vessel. As a result, the initial investment, maintenance, and installation costs are substantially reduced and the operation, safety, and reliability significantly improved.

Introduction
The mooring chain handler, located on the centerline of the vessel, can rotate in a horizontal plane about the center of a single chain locker allowing it to line up with the individual turndown sheave locations. This makes it practical to safely handle multiple mooring chains with a single piece of equipment.
The integral messenger wire winch, located directly behind the chain, guides the chain to the front of the mooring chain handler reducing the need for handling equipment such as cranes, davits, winches, etc.
The platform chain and messenger line is connected and disconnected at the front of the mooring chain handler eliminating the need for a special windlass wildcat normally used to pass the wire rope messenger line, connector, and platform chain.

Mooring Chain Handler
The mooring chain handler (Fig. A1) is a horizontal shaft type wildcat mounted in a frame that rotates on a circular foundation. The wildcat is centered directly above the chain pipe. The mooring chain handler can be rotated about the center of the chain pipe to lead the chain in any direction. The wildcat maintains the same degree of chain wrap for any horizontal orientation.
The messenger line winch (Fig. A2) is located above and behind the modified wildcat. The wire rope lead is always in line with the mooring chain lead. The chain handler is designed for 20% of the chain breaking strength. The winch drum is sized to handle the required length of wire rope messenger line.
Developing a Retrieval System for Subsea Sensors and Transmitters
Authors: Packman Clive , Braaten Nils 
Published: October 2011

Abstract
Operators are facing increased complexity in their subsea operations with up to 1,500 subsea sensors and transmitters installed each year [1].
Whereas the retrieval of topside sensors has proved to be very successful delivering significant cost savings, operators face maintenance difficulties and costly subsea interventions in upgrading and replacing subsea sensors.
This paper will look at how subsea technology has evolved to enable operators to retrieve subsea sensors, allowing them to better maintain existing instruments, replace failed ones and install improved versions. Such developments can save customers millions of dollars by reducing the cost and time required to maintain subsea assets.
The paper will look at the challenges Roxar faced in developing the first industry-wide subsea sensor retrieval system utilizing an ROV (Remotely Operated Vehicle) and which was evaluated by a consortium that includes BP, Chevron, Shell, Total and Statoil.
The paper will also examine the key elements of the system including the ROV tool and the Hydraulic & Control System, which enables the ROV to control the retrieval tool. Testing results and applications will also be referenced. The paper will interest all operators looking to optimize their subsea equipment and address a challenge commonly faced by everyone in the deepwater offshore production industry.

Introduction - The Market Need
As oil and gas companies in Brazil and elsewhere continue to pursue complicated and costly exploration in deep and remote waters while, at the same time, looking to optimize production, there is an increased demand for better data and intelligence on operating conditions subsea and downhole.
Whereas a single production field may have 20 to 30 operating wells, with more than 40 production trees and manifolds, each of these assets can have anywhere from five to 15 monitoring sensors mounted with up to 1,500 subsea sensors and transmitters installed each year. Such instrumentation measures pressure, temperature, and sand erosion or corrosion, and is retrieved from trees, manifolds and other process systems. Furthermore with a predicted annual deepwater spending to reach US$35 billion by 2014 [2], the deployment of these sensors is only likely to increase.
It is these sensors that provide operators with increased visibility to production variables, early indications of degrading asset health, and early warnings of impending abnormal situations. As intelligent sensor usage increases and production environments become more complex and remote, the demand for easier ways to maintain these assets becomes paramount to improved reliability and lower operating costs.
A December 2009 Emerson survey [3] of subsea specialists, for example, found reliability to be the most important criteria in subsea installations today (see figure 1) with a further 89% welcoming a system that could retrieve instrumentation during production.
Limits of Acid Fracture Conductivity Correlation Improvement Through Acid Fracture Surface Characterization
Authors: Rodrigues Valdo Ferreira , Medeiros Ana Catarina 
Published: October 2011

Abstract
The classical theoretical framework of fracture conductivity for rough acid-etched surfaces is the Nierode and Kruk correlation, given by an exponential equation of two parts: the conductivity under zero closure stress and the rate of conductivity change with closure stress. The first part has been related to fracture width and the second one, to rock embedment strength. This study, based on experiments that used samples from whole cores of an oil producer limestone, analyzed the fitness of laboratory-measured conductivities to the exponential conductivity correlation model. By means of a comprehensive 3D acid-etched surface characterization, this study showed that the use of surface parameters, measured at zero closure stress, can improve only the first part of the exponential correlation. The rate of conductivity change with closure stress is determined by the fracture width reduction under closure stress, while the effects of asperities in contact and related tortuosity are small. This conclusion is based on a physical hypothesis, on correlations of the surface parameters with the mentioned parts or coefficients, and on the relation between contact area ratio and fracture width reduction. The best acid fracture conductivity correlation developed has its first part based on a surface characterization parameter and the second one based on the rock embedment strength. This correlation showed superior accuracy compared with the Nierode and Kruk correlation and represents the maximum possible improvement through the use of surface parameters for the studied limestone. There is still significant room for improvement in the rate of conductivity change with closure stress. This requires a new model of fracture width deformation under closure stress or at least the replacement of the rock embedment strength for a more representative rock strength parameter.
Costing the Earth - Oil Spill Response and Ecosystem Services
Authors: Wright Nigel Howard 
Published: October 2011

Abstract
The scale of loss resulting from the Gulf oil spill and the formidable costs of liabilities has stimulated demands for rethinking our values and how they are integrated in key decision making.
Recent experience in oil spill risk assessments will be presented to highlight the criticality of smart stewardship of environmental capital and services by responsible governments dealing with energy development in biodiverse and sensitive coastal zones.
All too often the $ value of ecosystem services are only recognized when their functions are lost and have to be replaced e.g. excavation of coral reefs which protect islands for construction material- which has to be later replaced by concrete coastal barriers or removal of mangroves for coastal development with consequential increases in erosion and decline in fish populations and diversity.
Initial steps in paying for ecosystem services have been made through paying landowners to manage land to reduce flood risk or maintain downstream water quality and in carbon sequestration(under the clean development mechanism)provide a conceptual template for the future. At a global level, attempts have been made to place a $ value on the worlds natural capital and ecosystem life support services. These values need to be incorporated in today's oil spill contingency planning and protection priorities.
A critique of cutting edge formulae for placing ecosystems services on the balance sheet of the public and private sectors, and also the benefits of biodiversity offsets, will be presented. A pioneering approach to how these can be applied in due diligence of investments and oil spill risk assessments over the life cycle of oil and gas developments will be presented. In the future capturing ecosystem services in strategic tradeoffs and decision making in new concessions, oil spill contingency planning, and cumulative effects of long term production water discharges will be on the agenda of governments developing energy resources. Impairment or damage to ecosystem services will have to be paid for in line with the polluter pays principle.
This approach will establish a fundamental benchmark in visible corporate social responsibility in addressing stakeholder values future oil spill emergencies.
Challenges and Solutions in the Development of a Flexible Cryogenic Pipe for Offshore LNG Transfer
Authors: Eide Jorgen , Bernson Magnus , Haakonsen Rune , Frohne Christian 
Published: October 2011

Abstract
Offshore production of LNG will soon be a reality as several oil companies are working on projects aimed at building large floating LNG production units in the near future. Tandem loading has been used to transfer crude oil between two floating vessels for several decades worldwide and the time has now come to transfer of LNG in a similar manner. In areas with harsh weather, the vessel motions will require the loading to be performed in a Tandem configuration and flexible pipes / hoses are required as transfer arrangement between the two vessels to accommodate the relative vessel movements. Framo Engineering has together with Aker Pusnes, Kongsberg Oil&Gas Technologies (KOGT), Nexans and MIB developed a tandem loading system for LNG named the " Offshore Cryogenic Transfer System (OCT)??. This paper describes the successful development, manufacture, testing and approval of the double walled corrugated, stainless steel vacuum insulated flexible pipe designed for offshore transfer of Liquefied Natural Gas in the OCT system.

The Goals and the Challenges
Offshore transfer of LNG has been discussed for decades. The obvious solution is to " copy?? the methods and procedures that have been developed and refined by the crude oil loading industry in more than 20.000 offloading operations in areas such as the North Sea. One main challenge with a offshore offloading system for LNG is the need for a flexible hose that can maintain its functions and integrity at a temperature of −164 degrees C. Bonded reinforced rubber hoses are used to transfer crude oil and are also used for LPG transfer, however, the exposure temperature is limited to approximately - 50 degrees C. None of the conventional hose materials will offer the required mechanical properties at -164 degrees C. However, some metals maintain or even improve their properties at cryogenic temperature and 316 Stainless Steel is one such material. Nexans in Hanover has manufactured and supplied corrugated stainless steel vacuum insulated pipes to the cryogenic industry for many decades and have developed extensive know-how on the manufacturing process.
A Joint Industry Project was carried out in 2000–2004 to develop, manufacture and test a 10.5?? ID flexible pipe. The pipe design was based on Nexans manufacturing technology and KOGT riser technology. The project was successful, but in the years to come it became clear that a larger pipe with higher flow capacity would be required. A second JIP was carried out in 2007–20010 with the purpose to design, build and test a 16?? ID flexible pipe, based on the experiences gained in the first JIP.