bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seismic Normal Compaction Trends and Lithology
Authors: Ebrom Dan 
Published: May 2013

Abstract
Eaton's method, the standard method of determining pore pressure from seismic velocities, has been adapted from logging techniques. It requires the use of a normal (i.e. hydrostatic) compaction trend specific to very-low-silt shales, and also that the analysis only be performed upon relatively silt-free shales. As a practical matter, the gamma ray log is used to distinguish shales which are low enough in silt to be appropriate for comparison to the normal compaction trend. (Other methods of determining pore pressure from sonic velocities, such as Bowers (1995), also require a normal compaction trend for low-silt shales and restrict the analysis to very-low-silt shales.)
The obvious challenge in applying Eaton's method to seismic velocities is that all lithologies present in the subsurface contribute to the seismic interval velocity, and not just the shales. Again, the logic for practical matters is that, since shales are the most statistically likely lithology (at least in the Tertiary GOM), then a large enough velocity analysis window will be dominated by shales in terms of the velocity response. Hence one must be careful not to use velocities with too high a vertical resolution for fear of too strongly mixing lithology velocity responses in with pore pressure velocity responses. The exact limit of useful vertical resolution is debatable. Alan Huffman, at the 2010 SEG Annual Convention, opined that velocity analysis vertical resolutions finer than 1000 feet begin to run the risk of lithology effects. As likely, the highest useful velocity resolution is probably both depth- and area-specific.
But since pore pressure prediction from seismic velocities is routinely performed and found to be useful, these problems are clearly not insuperable. One of the key issues is to pick a normal compaction trend that honors the siltiness level of the local geology by adjusting the trend away from a pure shale compaction trend to that silty shale which is statistically the most likely in the region and depth of interest. As a practical matter, this can be performed by manually altering the compaction coefficient of the compaction trend until the resulting predicting pore pressure agrees with mudweights, well formation pressure tests (RFTs and MDTs), and other drilling information. Alternatively, if the compaction trend is calculated explicitly using volume of clay (VClay) as an input, then the VClay is manually altered until the predicted pore pressure agrees with the mudweights, MDTs, etc. In essence, the problem is solved by simply calibrating it away.
Carbon Fiber Armors Applied to Presalt Flexible Pipe Developments
Authors: Hanonge Didier , Bernard Gary , Do Anh Tuan 
Published: May 2013

Abstract
Pre-salt fields discovered in offshore Brazil require flexible pipe structures capable of reaching water depths of 2,000 meters and beyond.
Over the past decades carbon fiber technology has been widely used in a number of industries and is now ready for introduction to the flexible pipe industry. As a demonstration of what will be possible with composite materials in the near future, this paper will present the benefits of Carbon Fiber Composite armors and why it will be a game changer.
For example, this technology dramatically increases the achievable range in free hanging riser configurations, resulting in optimization of ancillary equipment and faster installation. Furthermore, the fatigue performance and corrosion resistance result in a higher safety factor with improved product service life.
A comprehensive qualification campaign, including prototype testing at conditions more severe than the pre-salt field specification, has resulted in a new design of flexible pipe using Carbon Fiber Composite that can be considered a qualified technology.
The present paper will focus on the carbon fiber integration within flexible pipe technology. We will go a step after the other from the material qualification tests, to the carbon fiber armors demonstrated fatigue performances, and in the end in the flexible pipe design and manufacturing.
Liuhua 11-1 FPS Dry-dock Upgrade and Life Extension - Mooring System Evaluation and Optimization
Authors: Zhong Wen Jun , Liu Bo , Luo Yong , Yang Hui , Yin Han Jun 
Published: May 2013

Abstract
The evaluation of existing mooring system and the development of an appropriate optimization design became the key issues in the Liuhua 11–1 FPS dry-dock updating project because this optimized mooring system has to face new challenges, such as the update of site metocean conditions, the revision of wind force coefficients due to upgraded topsides, and the additional corrosion allowance for chain links due to extra 15-year service life extension compared with the original system design.
A design team was formed to give the evaluation of the existing mooring system based on mooring line tensions and offset limits according to the latest industry standard for a permanent mooring system. Since the existing mooring system marginally failed the design requirements based on the evaluation, system optimization design focused on the adjustment of mooring line pretensions has been carried out to improve the mooring system performance and eventually to satisfy the classification requirements for the tension safety factors and the platform offset limits driven by the riser designs. The mooring system analysis was conducted in time domain. The Ariane program developed by BV was used in the detailed mooring system analyses. For the calibration and verification purpose, the system evaluation and the optimization design had also been independently verified with DNV's DeepC program.

Introduction
The LH 11–1 oil field is located about 200km southeast of Hong Kong in the South China Sea in approximately 310m depth of water. LH 11–1 FPS, which named ‘Nanhai TiaoZhan’, is a major component of LH 11–1 oil field development. The FPS was a modified drilling semi-submersible converted from a Sedco 700 series drilling rig built in 1975 and in 1995, it was converted again to a floating production unit in Singapore and then deployed at LH 11–1 oil field, permanently moored by 11 mooring legs. The Unit is classed by American Bureau of Shipping (ABS). It was originally designed for a service life of 10 years (from 1995) and has been continuously operating for more than 15 years. At the same time, a new oil field Liuhua 4–1 (OTC-24042), about 11 km away northwest LH 11–1, was in development planning with the utilization of LH 11–1 FPS facilities through a subsea tieback. Therefore, additional topsides capacities and the life extension of this aged semi-submersible FPS became necessary. CNOOC Ltd, Shenzhen is the owner of this LH 11–1 FPS. COOEC was selected as the contractor for the engineering and construction support of this FPS dry-docking upgrading and life extension project. CSSC Guanzhou Huangpu Shipbuilding Co., Ltd was contracted by the owner as the dry-docking shipyard for the upgrading construction.
Effects of Fiber Rope - Seabed Contact on Subsequent Rope Integrity
Authors: Head William , Del Vecchio Cesar J. , Ayers Ray R. , Devlin Paul V 
Published: May 2013

Abstract
A 12-month research project was initiated in September 2012 funded by the Research Partnership to Secure Energy for America (RPSEA) and industry partners with the goal of investigating the effects of polyester mooring rope segments contacting the seafloor prior to installation as part of a deep-water mooring system. It is possible for some soil particles to bypass the particle filter, become embedded in the rope core, and intensify normal fretting wear damage as the installed ropes respond to the cyclic loads resulting from extreme weather forces (such as hurricanes).
Potential soil ingress into rope due to accidental contact with the seabed may affect the long-term integrity of the mooring system and increase the risk for failure. This situation, in turn, places nearby subsea and surface infrastructure at risk. This investigation may also provide the ability to qualify particular rope designs for pre-installation on the seabed prior to hook-up. This option would greatly reduce overall risk by reducing the time required to hook up mooring lines to a floating facility, thereby reducing time to reach a safely moored condition before arrival of severe weather.
This paper describes progress in (1) performing experiments to investigate particle ingression and migration, and soil particle impact on cyclic wear (including hypothesis of mechanisms) and (2) full-scale tests exposing rope segments to the offshore seabed and then performing bench-type subrope soil-ingression sampling and full-scale subrope cyclic wear testing to determine the impact of seabed soil contact on the long-term performance of a mooring system.
An important project goal is to reach agreement between industry participants and US regulatory agencies to qualify polyester mooring ropes for incidental seabed contact and seabed pre-installation.
Subsea Pipeline Repair by Composite System: One Step Deeper
Authors: SLIMANI Hacen , BOULET D&apos;AURIA Stanislas , GAFFARD Vincent , WIET Paul , POPINEAU Dominique 
Published: May 2013

Abstract
Composite repairs are increasingly used in the oil and gas industry, for temporary repairs and for permanent repairs provided long-term performance is demonstrated. Composite repair systems are mainly used for onshore pipelines or offshore topsides. They are generally made of fibers tapes (aramid, glass …) impregnated with epoxy resin and then wrapped around the pipe. The number of fibers tapes layers and the repair length is determined from design calculations following standards such as ISO/TS 24817 or ASME PCC-2.
For subsea application of composite repair, five main issues must be considered:–pipe preparation: coating removal and surface preparation are necessary to ensure adhesion of the repair,–resin properties: the resin working time must be extended to allow fibers tape preparation above water and application under water,–repair performance: it must be demonstrated that underwater application do not affect repair strength,–repair system application: this is mainly a manual task today which can be performed by divers but is not applicable for deepwater,–design to lateral buckling and collapse: specific design criteria and limit states of composite repair must be determined for deepwater.
Several tests of divers' assisted underwater applications have been performed under third party supervision, using a specifically developed epoxy-resin. The experimental database covers repairs of through thickness defects and localized wall thickness reduction up to 80%. All tests results were comparable to results obtained for above water repairs and evidenced that the original pipe strength was fully restored.
In parallel, a specific tool has been developed to apply automatically the repair system with two main objectives:–to improve quality and repeatability of the wrapping operation, with applying constant tension and winding path,–to allow diverless (ROV) applications, which is a pre-requisite for deepwater applications.
This tool has been already tested underwater in the " semi-automatic" mode (operated by divers) with a positive feedback.
Composite system is, technically and economically, a promising way to repair subsea pipelines. There are no more restrictions to consider composite repair systems for shallow water applications. Additional tests with ROV, as well as collapse and bending resistance tests are now to be performed to open the way to deepwater repairs.
Study on Development Scenarios of Gas Fields around the Continental Slope of South China Sea
Authors: Feng Wei , Xie Bin 
Published: May 2013

Abstract
The Liwan 3–1 gas field, situates in block 29/26 with an average water depth of 1,300m, represents the first major deepwater discovery in the South China Sea. The development scenario of Liwan 3–1 indicates potentially an efficient way for those gas fields around the continental slope of South China Sea. Before the first appraisal well being drilled, CNOOC Research Institute was commissioned to carry out Liwan 3–1 feasibility study on December 27, 2007. This paper provides an overview of several development scenarios based on the limited data of Liwan 3–1 such as wells information and assumed data such as reservoir profile and pressure. In view of those potential discoveries near Liwan field, regional development strategy is also taken into consideration. As a result, the suggested development scenario is subsea wells tieback to Boosting and Processing Center (BPC). Through BPC, the natural gas is processed and boosted via shallow water pipeline to onshore terminal plant. BPC is actually not only a feasible scenario to speed up Liwan 3–1 development, but also a regional solution for potential fields near Liwan 3–1.

Introduction
The Liwan 3–1 gas field is the first discovery in the deepwater of South China Sea and shared by CNOOC and Husky. Liwan 3–1 locates at a water depth of nearly 1500m and about 65km from PY30-1–1. The discovery of Liwan 3–1–1 well in 2006 showed that the gas production rate almost reaching 5 billion m3/a. Two appraised wells named Liwan 3–1–2 and Liwan 3–1–3 were also completed in the end of 2008 and in the middle of 2009 by West Hercules semisubmersible drilling platform respectively followed by another appraised well later.
In this paper, several development scenarios of Liwan 3–1 gas field are demonstrated firstly. Then the scenarios of BPC (Boosting and Processing Center) are also studied based on a regional development view of potential fields near Liwan 3–1 and the scenario of one APP (accommodation and power platform) plus two PCPs (processing and compressing platform) is recommended. In view of minimizing investment and adopting regional development scenario, subsea wells tieback to BPC is suggested for the development of Liwan 3–1.
Design and Verification of High Load Bearing Interfaces
Authors: Peters Dan , McKie Nigel 
Published: May 2013

Abstract
Exactly how we are to verify the design of HPHT equipment is still being debated. It is almost certain to involve some form of Finite Element Analysis (FEA). FEA is well established as a stress analysis method for use in conventional Pressure Vessel design; however it is not so well established for load bearing interfaces. This leaves a gap in our Design Methods, since load bearing interfaces are intrinsic to Wellhead Equipment Pressure Vessel design. Intrinsic because many of our Pressure Vessels are " capped" by hangers and connectors instead of flanges; if a hanger Load Shoulder fails then the Pressure Vessel above it has failed.
The oil and gas industry would like to make more use of the expertise and experience of ASME but need to assess the consequences of applying ASME's methods product wide. It is possible that ASME VIII can be expanded to make it more directly applicable to the oil industry.
Unique to the oilfield are infrequent but extremely high loads. These loads are much higher than the Working Condition and in most cases they stem from field testing and emergency situations. If the established ASME methods are used for these cases certain projects may not be viable.
The authors will present analyses that assess the load bearing capacity of various field proven Wellhead Equipment designs against some of ASME's Design Criteria.

Introduction
It is essential that we provide clear guidance for engineers designing HPHT oilfield equipment. This involves establishing realistic and uncomplicated Design Criteria: a quantitative method for determining if a design will be fit for purpose or not.
There are many aspects of a design that need to be addressed: Plastic Collapse, Local Strain, Ratcheting, Shakedown, Tri-axial Strain, Serviceability, Fatigue etc… The primary topic of this paper is Plastic Collapse which is usually the starting point for design.
ASME VIII is a code written specifically for Pressure Vessel verification. It is made up of three divisions. Division 1 is a basic design code for simple low pressure vessels. Division 2 is an alternative set of rules that makes use of higher allowable stresses but with more rigorous design and analysis requirements. Division 3 is for the design of high pressure vessels, which are generally defined as being above 10 ksi and allows even higher stress levels. To maintain the same level of safety the higher divisions require progressively more stringent verification methods. Higher allowable stresses lead to the possibility of more compact technology and weight savings, but it is also a way to design viable High Pressure equipment by allowing thinner wall sections, which will allow reliable heat treating. Excessively heavy wall sections can make it difficult or impossible to heat treat and achieve uniform properties through the thickness.
Hero: A New Tool for Hull Inspection
Authors: BECART Romain , Bouchet Christophe 
Published: May 2013

Abstract
The purpose of the underwater inspection of F(P)SO and FSU hulls is to verify the floater's integrity and ensure the safety of personnel and production equipment. It is required by internal rules and by international maritime conventions applicable to floating units.
Today, hull inspections are performed by divers who operate in relatively deep waters (down to 30 m), on live installations and in an open sea environment subject to swell and variable weather conditions, all of which add up to significant risks for the divers' safety. These operations also involve mobilizing considerable logistic means for several weeks (support ships, decompression chambers, numerous teams).
An integrated solution has therefore been developed to perform this task with dedicated ROVs. It offers important advantages not only with regard to safety by limiting the number of diver interventions and thus the risk of accidents, but also in terms of reducing OPEX, as the HERO can operate for longer than divers and in harsh sea conditions which usually limit the duration of diving campaigns.
HERO is now under qualification and the first industrial trials have started.
This paper develops the method for specifying the equipment, positioning the system with NDT measurement tools (CP and US probes, magnetic sensing), HP cleaning and operational deployment. It also presents the results of various qualification tests carried out in the laboratory and the harbor to develop this new technology such that it satisfies hull inspection specifications.
HERO inspection methodology and performance have now been qualified by the main classification companies (Bureau Veritas, Lloyd's, DNV, and ABS).
The main applications envisioned for this solution are:Underwater inspection in lieu of drydocking (UWILD) for classification requirementsAccurate hull evaluation for life-extension purposesAssessment of floating assets prior to sale or conversion
A Comparison of Dynamic and Static Pile Test Results
Authors: Stevens Robert 
Published: May 2013

Abstract
Class A predictions of static pile capacity for three projects are presented. Pile driving is monitored using strain transducers and accelerometers attached near the pile top. The CAse Pile Wave Analysis Program (CAPWAP) is used to estimate the distribution of the soil resistance to driving along the length and at the toe of the pile. The static capacity is predicted from dynamic pile test results and compared to the actual static load tests.
Our first case history is for two 1235-mm-diameter steel pipe piles driven to penetrations of 12.5 and 20 m with a Junttan HHK 14S hydraulic hammer. When the piles were redriven, there was little change in the shaft resistance and end bearing. Therefore, the shaft resistance obtained from the CAPWAP analyses was compared directly to the results of tension tests performed about 50 days after redriving.
Our second case history is for a 914-mm-diameter steel pipe pile redriven using a Berminghammer B-6505 diesel hammer in dense to very dense silty sand to sand, stiff to very stiff clay, and very dense silty sand. The pile was redriven 46 blows for 25 mm of movement, and CAPWAP analyses were performed at the beginning and end of restrike at 47.5-m penetration. The minimum compressive pile capacity was predicted by adding the shaft resistance for Segments 1 through 13 at the beginning of driving and the shaft resistance for Segments 14 through 24 at the end of driving, and compared to a load test performed 5.5 months after driving.
Our third case history is for a 2000-mm-diameter steel pipe pile driven with a Menck MRBS 5000 steam hammer to a penetration of 30.6 m in very silty clay. The compressive pile capacity was predicted for a load test performed 52 days after driving using CAPWAP results for the end of initial driving and the beginning of restrike after a delay of 43 hours for one of the reaction piles and an estimated dissipation in pore pressures.
Rigless Intervention: Case Studies, UK and Africa
Authors: Bosworth Phillip , Willis Oliver 
Published: May 2013

Abstract
This paper describes and highlights, via two case studies, the benefits of conducting rigless subsea well intervention from specialist monohull vessels. The case studies provide an overview of the operations on subsea wells, from intervening through the production tree (XT), to XT change-out and well P&A / wellhead removal operations.
A brief overview of rigless intervention techniques and equipment is also described.
The operations described in the case studies were completed in two very different operating regions. The United Kingdom North Sea (UKCS) and West Africa (Equatorial Guinea).
In the first case study, the paper describes how over a 68 day period a Light Well Intervention Vessel (LWIV) successfully and safely performed mechanical repair & well maintenance (and well integrity surveillance); data acquisition (production logging), well suspension (for a XT recovery); scale-squeeze pumping operations (production enhancement) and finally well plug and abandonment (decommissioning) on a variety of wells across several subsea Fields.
The second case study summarises a 105 day campaign in which a LWIV was contracted to undertake subsea well interventions (for both well maintenance and production enhancement needs) and a temporary well suspension (for a XT change-out) on multiple subsea wells within a Field. The vessel optimisation, through performance, coupled with its ease and speed of transit and set up (DP3 rated) were key to this particular campaign as the 7 wells identified to be worked on by the Operator were a number of kilometres apart precluding the efficient use of a moored unit.

Introduction
Rigless and Riserless Light Well Intervention (RLWI) activities have been executed for over 25 years across the North Sea. The purpose of these case studies is to demonstrate that with effective project management (planning, developing, execution and close-out) the use of RLWI is both a flexible and extremely cost effective method which Operators can utilize for a single well, or across a number (a campaign) of subsea wells, irrespective of subsea tree type or close proximity.
Case study #1 outlined below summarizes the flexibility & efficiency of multi-service LWIV in the North Sea with the ability to perform intervention/subsea operations in a cost effective and efficient manner, allowing remedial operations to be conducted in order to maintain well integrity, and other remedial well servicing techniques in order to maintain and often enhance hydrocarbon production (manage life of well productivity) before eventual Cessation of Production.