bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fatigue Testing of Shrink-Fit Couplings for Joining High Strength Steel Riser Pipe
Authors: Shield John , Bowman Jonathan , Wightman John , Pappas James 
Published: May 2013

Abstract
The shrink-fit connection has been designed and developed to enable the manufacture of high pressure deepwater riser systems when traditional pipe join methods such as welded or threaded and coupled are not feasible. For example, welding may not be suitable for joining high strength steels due to hardness limitations.
Shrink-fit technology has been employed for manufacture of a full bore, high pressure, shallow water drilling riser system in the North Sea. For this application, development testing focused on static capacity, sealing, and manufacturability, as joint fatigue life was not a limiting design case.
In 2012, Subsea Riser Products (SRP) and RPSEA, together with project champions Chevron and BP, collaborated to investigate the potential of the technology in deepwater drilling and production riser systems. In these systems, riser weight and fatigue life often drive the design, motivating the use of thinner wall, high strength steels and efficient, fatigue resistant connections.
SRP's analysis had previously demonstrated the shrink-fit connection's potential: very low geometric stress concentration factors (SCF) and parent metal material classification.
A test program was devised to test the manufacturability of shrink-fit joints made from high strength (&gt;100ksi) mill pipe and forged couplings. This aspect of the program demonstrated the economic viability of the technology, by using readily available project materials; and a construction method that could potentially be used on riser installation vessel (e.g., J-lay).
A second aspect of the test program focused on the installed performance of the connector: burst, sealing, and fatigue life. Six specimens were produced and tested on a resonant bending rig at various stress levels to produce an indicative fatigue curve. Metallurgical failure analysis and comparisons with calculated results then enabled development of a plan for future testing and improvement of the connector performance to commercialize it for deepwater use.
New Developments in the Simulation of Slurry Behaviour in Spooled Hoses for Offshore Mining Applications
Authors: Rhee Cees van , Munts Edwin , Bosch Jochem van den , Lotman Rick , Heeren John 
Published: May 2013

Abstract
The presentation will describe the developments to analyze mining slurries in spooled risers and the benefits of this knowledge in de the design process of spooled risers.
Current technology in deep sea mining applications dictates that the slurry produced by the seabed mining tool is transported using a flexible riser to the vertical riser inlet. The vertical riser, similar to oil & gas risers, is a series of steel pipes which transports the mineral slurry from the seabed to the mining support vessel. New developments in riser technology enable flexible hoses to be used for applications in water depths up to 500 meters.
In this application, a single riser using flexible hoses is used for transporting the slurry from the Seafloor Mining Tool (SMT) to the Mining Support Vessel (MS). The advantages are (i) that the flexible riser can be launched and recovered by spooling it on a drum installed on the mining support vessel and (ii) can cater for varying water depths.
In the section of flexible hoses spooled on the drum, the slurry behaves differently from what might be expected. The paper starts with a description and consequences of the phenomena that occur in elbows and in the spooled hoses at the entrance of the spool. Followed by the development of the slurry to a new stratification regime along the first part of the spooled hoses and finally the phenomena which occur thereafter. The envelope of slurry conditions (concentration, particle size distribution and velocity) have an impact on the dynamic pressure losses in the spooled hoses.
Insight into the slurry behaviour is obtained using 3D CFD simulations. Verification is performed with information retrieved from literature. To represent better the slurry behaviour a pressure ratio, Rpressure, is introduced, which is the local pressure gradient in the spool divided by the pressure gradient of a straight pipe. When the total pressure ratio is calculated over a typical length of a design configuration, like an elbow or complete turn, this figure can be compared with other results found in lecture. The envelope of this figure along its design length is even more important. The changes can be related to changes in mixture behaviour.
The new insights not only explain why some slurries show the secondary flow of Dean and others don't, but also why some slurry mixtures show lower dynamic pressure losses compared to slurry in a straight pipe. From a practical point of view construction parameters as the spooled riser diameter to drum ratio and consequences of alignment in the horizontal or vertical position are discussed.
Including Enabling Technologies in the Wellbore Construction Basis of Design: Smart Strategy to Benefit From Casing While Drilling, Open-hole Expandable Liners, and Liner Drilling
Authors: Siddiqui Asim A , Karimi Moji 
Published: May 2013

Abstract
Historically, conventional drilling has been considered the method of choice for drilling challenging wells; substitute methods have been used only if conventional drilling has failed or proved ineffective. Some of these innovative alternatives are Casing while Drilling (CwD), expandable liners, and liner drilling (LD). This study investigates how inclusion of these enabling technologies in the basis of design (BOD) can help operators achieve greater benefits in comparison to use in contingency plans. Casing/Liner Drilling has been successfully employed as a solution to lost circulation and wellbore instability. Moreover, casing/liner seats can be optimized and pushed further, taking advantage of Plastering Effect wellbore strengthening. Due to the different drilling dynamics of Casing/Liner Drilling, special measures should be taken to maximize the effectiveness. Unfortunately, sometimes the implementation of these measures is compromised since they have not been included in the BOD. This study reviews these issues and provides recommendations. Open-Hole Solid Expandables can be used in telescopic deep-water well plans, primarily to save borehole diameter and hence improve production. Usually more troublesome zones are encountered as we drill deeper, hence the time window to leave the wellbore open will be shorter. It is recommended that expandable liners be used further up the wellbore in a lower risk environment as opposed to trying to save diameter after the casing has been set higher due to drilling problems. Examples are provided demonstrating the benefits of including the technology in the BOD. As wells get more challenging, the industry needs to pull alongside the enabling technologies accordingly. CwD, LD, and Solid Expandables are proven drilling hazard mitigation technologies, which if included in the well plan early can be implemented more effectively than if considered as contingency plans.

Introduction
Lost circulation and wellbore instability have plagued the drilling industry since its onset. Despite extensive research aimed at understanding the occurrence mechanism for these unwanted events, the solution has been the same for a long time; setting additional casing and adding lost circulation material to the drilling fluid have been the only option. On the other hand, the complexity of wells and severity of problems have constantly increased to the point that some prospects are simply undrillable with conventional methods, or they incur a huge time/cost burden that challenges the economic feasibility of the project. Only in the past decade have new solutions such as Managed Pressure Drilling (MPD), CwD, solid expandables, etc., emerged that allow new prospects to be explored, and provide new life for fields considered for abandonment because they had reached the technical limit of conventional methods.
First Floating, Production, Storage and Offloading Vessel in U.S. Gulf of Mexico
Authors: Ganguly Partha , Mastrangelo Carlos Ferraz , Daniel Jeremiah 
Published: May 2013

Abstract
This paper is based on work performed during design, implementation and operation of the Cascade and Chinook fields in ultra-deep waters of the U.S. Gulf of Mexico. It describes how Regulatory compliance was accomplished for this the first Floating Production Storage and Offloading System in the Gulf of Mexico and the decision making towards selecting a disconnectable Floating Production Storage and Offloading System and critical activities from award to operation of this innovative disconnectable Ultra Deep Water FPSO in over 8,200 feet of water, making it the deepest moored FPSO. It is an Early Production System (EPS) that will establish production potential prior to installing the full production facility for the production potential anticipated. Crude is offloaded by tandem offloading to Jones Act shuttle tankers.

Introduction
The path Petrobras took, from applying for approval from the U.S. Regulatory Agencies for the use of a Floating Production Storage and Offloading system (FPSO) with tandem offloading to purchase of the Cascade and Chinook (C&C) fields and to produce both fields with a FPSO, was challenging in many ways.
Petrobras accepted the challenges of having to incorporate new technology, breaking records in the process to achieve production in these ultra deep water fields, complying with Regulatory Agencies requirements that did not necessarily have language in the regulations that were specifically applicable for an FPSO in U.S. waters and to install an EPS FPSO to produce in gulf of Mexico where no FPSO had ever produced before.
FPSO technology for use as a production facility was considered state-of-the-art worldwide but was not yet accepted in the U.S. Gulf of Mexico (USGoM), when Petrobras embarked on the project to install the first FPSO in USGoM, realizing it would be a challenge. Petrobras development strategy was to produce C&C fields from a common facility. Petrobras successfully achieve their goal of producing the C&C fields with the first FPSO in the USGoM. The EPS FPSO, BW Pioneer, is currently producing from both these fields.
This paper will provide insights into the path taken to successfully complete this challenging project that included; close cooperation with US Regulatory Agencies to accept FPSO production facilities, changes in ownership of the fields, submission for approval of concept to the MMS and USCG, steps in the project to get the leased EPS FPSO to the field and tools to assist operations and production.
Subsequent to completion of the C&C project, the US Regulatory Agencies preference has shifted from a permanently moored FPSO (as evaluated in the EIS) to a disconnectable FPSO (as approved for C&C fields).
GTL FPSO: An Alternative Solution to Offshore Stranded Gas
Authors: Ahn Sung-Il , Park Taeshin , Choi Dong-Kyu , Denholm Douglas , Lim Hye-Won , Kwon Hyuk , Zhang Lifeng , Kim Hyun-Jin 
Published: May 2013

Abstract
The sustained, increasing world energy demands have led to very high oil prices. In parallel, there has been a significant increase in interest in economic and environmentally sensitive solutions for the monetization of remote, stranded gas offshore. Current global natural gas reserves total approximately 6,100 tcf, according to EIA estimates. Roughly half of these are considered to be stranded gas that is uneconomical for market delivery due to the remote location of potential markets, lack of economic transportation and infrastructure, or lack of conversion technology. Such regions with significant stranded gas reserves include Northern Australia, Vietnam, and Indonesia.
GTL (Gas-to-Liquids) FPSO (Floating Production Storage and Offloading) offers an attractive new solution to monetize these remote, offshore, stranded gas fields. Products of the GTL process are clean transportation fuels ranging from diesel to jet fuel that can be readily used in the existing energy infrastructure. Although this option has been considered in the past by Syntroleum and Statoil in mid-2000, a reexamination of this option is warranted due to recent advances in both GTL and FPSO technology. New GTL commercial plants have recently begun production in Qatar, utilizing technologies by Sasol and Shell with the latest advances in the process technologies and catalysts. Membrane and Process Intensification technologies show considerable promise in making GTL an attractive option in the future. The newly built Oil FPSOs (Pazflor and Agbami) instill confidence that large oil and gas processing operations can be safely and economically performed on an FPSO.
DSME has recently completed a feasibility study as part of a multi-year development program to acquire the basic technology and engineering for GTL FPSO. An assessment was made on the technical feasibility of commercial and near-commercial-scale technologies, and a preliminary design concept of the GTL process was produced for the topside. This study utilized technologies that best met the needs of the FPSO application and the corresponding preliminary design concept of the hull to support the topside GTL process. Additionally, preliminary market analysis was performed to better define the scope of GTL products to be produced. Economic analysis was performed to identify the major cost factors and understand their sensitivity on Project economics.
The results of this feasibility study to date suggest that this GTL FPSO design concept is technically feasible. Its clean fuel and chemical feedstock would be attractive to the market, and the design concept is economically competitive within the range of the current Project cost factors. Future work will be directed to develop a more definitive process, hull design, and Project economics, and will bring commercial realization of this innovative approach of monetizing offshore stranded gas fields.
Liuhua 11-1 FPS Life Extension: Classification Society
Authors: QIAN WEI 
Published: May 2013

Abstract
The FPS, " NANHAI TIAO ZHAN", is a major component of the Liuhua 11–1 project. It is a converted from a Sedco 700 series mobile offshore drilling unit (MODU) into a floating production system. This FPS hull and mooring system are designed to maintain station in 100 years return typhoon environment.
The Semi-submersible FPS " Liuhua 11–1" registered ABS class. The latest request from the client was a comprehensive assessment for 15 years life-extension. According to the contract between the client and ABS, ABS surveyor should do multiple survey to this unit, including on-site inspection for the unit structure (welding and corrosion), steel plates thickness measuring, etc. In addition, ABS engineer should do strength re-assessment to the structure when received the submissions of Global Strength Analysis and Global Fatigue Analysis from the client, then make comments about structure reinforcement according to the re-assessment result. This paper is to list the related requirements from related ABS rules and guides, including ABS Guide for Building and Classing Floating Production Installations, ABS Rules for Building and Classing Mobile Offshore Drilling Units, ABS Guide for Fatigue Assessment of Offshore Structures, and other regulations, such as IMO Code for The Construction and Equipment of Mobile Offshore Drilling Units, etc., other industrial standards for reference during analysis.

Introduction
The Liuhua 11–1 oil field is the largest oil field in the South China Sea so far. It was originally developed by a consortium of Amoco, CNOOC and Kerr-McGee in 1995. The main components include a floating production system " NANHAI TIAO ZHAN", and a floating production, storage and offloading vessel " NANHAI SHENG LI" which is located about 3000 m northwest of the " NANHAI TIAO ZHAN" FPS.
The original Liuhua 11–1 project was the first deepwater development project in China with in more than 1000 ft water depth. Liuhua 11–1 project was one of the major deepwater developments adopting new technologies with unique features in early 1990's for the whole offshore industry. This oil field is still in production. A new oil field Liuhua 4–1, about 11km away from Liuhua 11–1, was planned to be processed by the Liuhua 11–1 FPS facilities via subsea tieback. In this regard, additional topsides capacities and life extension for the aged semi-submersible FPS " NANHAI TIAO ZHAN" were requested. Significant technical challenges were imposed to the project team for the life extension and dry docking upgrade of the FPS. The FPS upgrade project started in 2010, and riser and mooring offshore reconnection was completed in 2012. The upgraded Liuhua 11–1 FPS is now back to the oil field and in production again successfully.
Slug Response in Subsea Piping: Advancements in Analytical Methods
Authors: Kavanagh William Kieran , Connaire Adrian , Payne Jason , Connolly Aengus , McLoughlin Jonathan 
Published: May 2013

Abstract
During the life of certain offshore fields, slug flow can lead to alternating internal fluid conditions and irregular flow characteristics in subsea pipelines, risers and spools. These conditions generate time-varying fluid forces at locations of change in flow direction which can lead to significant vibration, fatigue damage and in some cases push structural utilizations above allowable limits. In recent years, slugging related problems have resulted in the change-out of critical subsea equipment.
Difficulties exist in predicting and characterizing slug flow in a representative manner due to the complexity of the loading. As a result, the current state of practice with regard to predicting response to slug flow is not considered mature technology and is not dealt with consistently across the industry. Furthermore, subsea design practice and analysis approaches, where they exist, lack sufficient validation. Widespread industry interest in the topic has lead to the requirement to develop enhanced analytical methods, full scale validation and industry guidelines.
This paper deals specifically with the mechanics of combining the various slug load contributors, including centrifugal, bend impact and fluid inertial loads in structural models and their effects on stress distributions in pipeline systems. The paper illustrates how enhancements in analytical methods now allow convenient definition of slug flow inputs and automatic generation of dynamic load time histories. Results are presented for a generic subsea piping configuration which is considered particularly susceptible to slug load response. A comparison of responses from different structural software packages is presented for representative design conditions and parameter variations.
Case Study: Heating Offshore Production Tubing Electrically for Crudes that Have Wax Issues
Authors: Parman David G. , Marron Andrew James 
Published: May 2013

Abstract
Wax buildup that would restrict the flow of the oil from the reservoir to the offshore platform was expected in several wells offshore New Zealand. Alternatives such as hot oiling, scraping and chemical injection were rejected, since electric downhole heating was the most efficient, economical, reliable, and environmentally friendly solution. The use of a unique, skin-effect electrical heat tracing system inside the production tubing was selected as the most efficient and cost-effective method. This heat tracing system involved a sealed coiled tubing, with an internal cable and filled with di-electric oil, that was installed in the production tubing. This created a skin-effect heater with maximum heat transfer and also ease of installation.
The use of heaters inside the production tubing provide a more effective and efficient system for flow assurance than external heaters on the tubing would. The heaters, called skin-effect heat tracers, covered the length from the reservoir to the topsides, some 1,700–2,000 meters (5,577–6,562 ft.). The reservoir temperature was only 50 0C (122 0F) and the crude had a Wax Appearance Temperature of 48 oC (118.4 0F), so even minor cooling could potentially cause wax buildup problems. Typically well flows were heated effectively during operations to ensure that the tubing head temperatures were 60-65 0C (140- 149 0 F) so that wax was never deposited on the tubing. The heaters can easily be adjusted at the surface to provide the required heat under varying operating conditions.
Skin-effect heating is an efficient, reliable, and easily adjustable method to prevent flow assurance issues that can be retrofitted to existing offshore or onshore wells The total system is very space efficient both downhole and on the platform.
Some of the conclusions include that the flow assurance issues of wax buildup and the resulting restricted oil flow were resolved in an economical and efficient manner. Also, this unique, first application of skin-effect heat tracing downhole for a deep offshore well provided reliability and economic returns on investment. Finally, this method can also be used to prevent other flow assurance issues such as viscous oils and to prevent hydrate formation.