bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Test Tank: Simulation of Ocean Engineering Problems by Computational Fluid Dynamics
Authors: Ortloff C.R. , Krafft M.J. 
Published: October 2008

Abstract
With the increase in knowledge in computer-based simulation methods and recent advances in high-speed computing, solutions to complex fluid-structure interaction problems, such as transient wave impact on fixed and floating structures, can now be studied in more detail. Numerical results, combined with model test measurements for verification, form the basis of the concept of the Numerical Test Tank (NTT) concept. Sample results of the application of Computational Fluid Dynamics (CFD) methods to the solution of two important ocean engineering problems are presented to illustrate the present methodology, and are then compared to model test results.
Specifically, CFD solutions are obtained for green water impact on a full-scale, FPSO hull and deck structure. The present numerical method employs a fully three-dimensional, transient, viscous Navier-Stokes solver based on the FLOW3D/ 96 CFD code. The results of the simulation are shown to produce at least qualitative agreement with model test results with respect to the shape of the incident, reflected and on deck- transient surface wave profiles. Some differences between the simulation and test results arise due to details of the simulation set-up, such as cell sizes, cell distribution, convergence criteria, turbulence model, and boundary conditions.
Additionally, CFD methods are used to compute current force coefficients for a scale model of a 200,000 DWT tanker. Computed force coefficient values are Froude-scaled and compared to OCIMF recommendations, which are based on Froude-scaled model test data. Preliminary CFD results indicate basic agreement with OCIMF data, however future computations of coefficients for a full-scale hull, and further analysis of test data will be necessary in order to investigate viscous scale effects in more detail. The apparent utility of the Numerical Test Tank, as illustrated by the example solutions presented, indicates that this computational approach holds promise for improving detailed knowledge of design loads for fixed and floating structures subject to severe wave and current loading.

Introduction
The design of FPSO systems for harsh wave environments often requires model testing of green water impact on deck structures. In 1993, SOFEC conducted 100-yr survival tests of the 140,000 DWT FPSO for AOPC's Liuhua field at MARINTEK; Figs. la, 1b and 1c show a typical sequence of on-deck green water flow and impact. During these tests, a limited number of instruments were used to determine impact loads on the turret surround structure and the breakwater protecting the process modules. The measured loads and volume of water which passed over the breakwater were sufficiently large so as to warrant a second set of green water tests at MARIN (Fig. 6). These tests were specifically designed to study wave impact and breakwater optimization. In September 1996, typhoon Sally passed within 10 nautical miles of the Liuhua FPSO, generating waves (88 feet) and winds (112 knots) associated with a 200-yr event.
The Mars Project Overview
Authors: Godfrey D.G. , Haney J.P. , Pippin A.E. , Stuart C.R. , Johnston D.D. , Oriean R.H. 
Published: October 2008

Abstract
The Mars Project is a $1.0 billion investment in a record breaking water depth of 2940 ft. in the Gulf of Mexico. As Shell's second Tension Leg Platform (ILP), it incorporates lessons learned from designing, constructing, and operatingShell's first TLP Project, Auger. The Mars TLP is a 53,000 ST displacement floating structure supporting full drilling and production facilities. Oil and gas are exported via 18- and14-inch pipelines, respectively, to a pipeline hub platform at WD-143. The design and contracting approaches for the Mars TLP were significantly affected by the need to improve project economics through cost reduction and schedule reduction. Thisresulted in an emphasis on topside payload reduction, a fit-for-purpose approach, elimination of components through innovation, overlapping design and fabrication activities, elimination of a hull design cycle, and a risk-sharingcontracting strategy. Design, fabrication, and installation of the Mars TLP was approximately $65 MM under budget and 3 months ahead of the approved schedule. This was an improvement on the Auger TLP results by more than $200 MM and I 1/2 years. The Mars approach to TLP design andcontracting has continued on Shell's ongoing Ram/Powell and Ursa Projects, with some adaptation based on Mars experiences.

Introduction
This paper is the first of 6 papers presented at a special session of the 1997 Offshore Technology Conference dedicated to the Mars Project. It is an overview of the project that ties the individual papers together. For detailed information, the reader is referred to the other five papers presented at this special session.

General Information
The Mars prospect comprises portions of six OCS leases in the Mississippi Canyon Area, located 130 miles southeast of New Orleans in 2940 ft. of water. Shell and BP Exploration are jointworking interest owners with 71.5% and 28.5%, respectively, and Shell as operator. The discovery well was drilled on Block 763 in 1989 by the Discoverer Seven Seas drillship. A total of five wells and five sidetracks were drilled from 1989 through 1991. The results of the drilling programs, 3-D seismic interpretation, reservoir simulation, and probabilistic cost estimates for various development systems led to selection of a TLP for field development in October 1992 and projectapproval in September 1993. Shell's current assessment of total gross ultimate recovery is about 500 million barrels oil equivalent from this phase of development. A future development phase is possible and could increase reserves to about 700 million barrels oil equivalent. The reservoirs at Mars are geopressured turbidite sands containing under saturated oils with an average GOR of 1,000 SCFIBBI. The API gravity ranges from 20 to 32° and sulfur content is 2-2.5%.
The Mars TLP has the capability to support 24 wells of which 10 were predrilled by the semi-submersible drilling rig. George Richardson. The remaining wells will be drilled fromthe TLP by the H&P 201 platform drilling rig.
Neptune Project: Spar Hull, Mooring and Topsides Installation
Authors: Kocaman Alp , Verdin Earl 
Published: October 2008

Abstract
This paper describes the installation of the Neptune Spar at Viosca Knoll Block 826, approximately 90 miles south of Mobile, Alabama in the Gulf of Mexico. Water depth at the project site is approximately 1,930 feet
The installation of the Spar was accomplished in two distinct phases. The first phase of the operations were completed about 3 months ahead of the arrival of the Spar hull at site. Inthis phase, the six anchor piles were driven and the six mooring lines were laid on the sea bed.
In the second phase of installation operations, hull towout to the site, ballasting and upending of the Spar hull on location, the connection of the hull to the six mooring lines and setting the production facilities were accomplished. The Spar hull was towed to site horizontally and upended at site by selectively ballasting hull compartments. The mooring lines were then attached to the hull. The mooring lines are a combination of spiral strand wire and chain with a sea beddriven pile at the far end. The placement of the buoyancy cans inside the Spar moonpool area (center well bay) which support the production risers, then completed the installation effort.

Introduction
The Neptune Spar hun construction was started in February 1995, the Phase I of the installation work was completed inJuly 1996, and the Phase II of the installation work was completed in September 1996. The facility was turned over to the client in November 1996 and the first oil was produced in February 1997. roughly two years after the construction and installation contract signing. Reference 1 provides further details of the management of me contracting, construction and installation strategy.
The hull was constructed by Aker Rauma Offshore (Reference 2) in Finland in two sections and transported to a shipyard in the Gulf of Mexico in two sections. J. Ray McDermott was responsible for fabricating the production facilities, towing thehull to site. upending it, installing the mooring lines, buoyancy cans, export risers and the production facilities.
Both in Phase I and Phase II installation operations, J. Ray McDermott's dynamically positioned derrick. barge DB-50 was used extensively.
Being the first of its kind, a variety of options for each phase of the installation have been considered. The result of some ofthe work completed to date will be valuable to other Spar type floating production system designs.

Phase I Operations
Phase I operations consisted of the placement of the anchor piles. the bottom chain and the spiral wire on the sea bed.
Two flexible export risers were also installed following the mooring wire installation operation, however, the production riser installation operations are nm addressed here.

Piled Anchors
The initial design of the Neptune Spar mooring system was based on the principle of holding the Spar in place by using high capacity gravity anchors. A drag embedment type of anchor, most frequently found in semisubmersible drilling rigs, would be utilized.
Improvements in Design of Converted FPSOs Regarding 20 Years Operation Without Docking
Authors: Assayag S. , Prallon E. , Sartori F. 
Published: October 2008

Abstract
This paper presents improvements on basic and engineering design of four converted VLCCs that will be operated as FPSOs in Brazil's Campos Basin.
Conbersion of these VLCCs is under way, worked on by contractors around the world, the first of them being scheduled to start operations by the middle of 1997.
Project economics demand that the units be operated during the next 20 years without docking. PETROBRAS offshore operations and maintenance expertise were applied to achieve this goal, meeting unique FPSO operating conditions. Experience and data gathered by project team members and technical staff are now being incorporated into next generation units, which are at present moment in Design Basis phase.
Although these improvements will only show their effectiveness after units come into steady operation, we are confident that major achievements in safety and economics have been made successfully.

Introduction
The discovery of Marlim and Albacora, giant deep water fields in Campos Basin, offshore Rio de Janeiro state, will allow PETROBRAS, a remarkable increase in national oil production. On the other hand, due to the difficulties related to deep water production, distance from the shore and from existing facilities, the start of commercial production of hydrocarbons from those fields as quickly as possible, in the most economical way, within good reservoir exploitation techniques and preserving the environment is also an enormous challenge to the Company.
The traditional solution adopted by PETROBRAS for offshore production, the utilization of semi-submersible platforms (SS) as floating production units (FPS) and the pumping of oil and dispatching of gas by pipelines or the pumping of oil through monobuoy, was used in pre-pilot and pilot units in Marlim field (P-XI11 and P-XX), Stationary Production Unit (UEP) N.l in Marlim (P-XVIII), and in Albacora field (P-XXIV and P-XXV). Other units of the same type are planned, such as UEPs 2 and 3 in Marlim (P-XIX and P-XXVI).
However, in order to complete development of the fields, it would be necessary to expand the pipeline network, by the construction of new pipelines, or by the installation of new monobuoys, considered to be the "weak links" in the system, as the existing pipelines could not stand the increased flow. The technical and economical viability study shows as the best option, the installation of FPSOs. Due to the estimated field life of 20 years, and considering the complexity of the pull-in and pull-out operations, the study indicates the permanency of the units on location until the end of the life of the field, without docking.
The definition of the necessary storage capacity of the FPSOs took into consideration the estimated oil flows forecast for the fields, the availability of the tanker fleet to be used as relief vessels and, aiming to reduce operational costs, a lower frequency of offloading operations.
With PETROBRAS having some VLCCs available, the option of converting them into FPSOs came into consideration.
Twisted Base Jacket
Authors: Frame Malcolm 
Published: October 2008

Abstract
The design of jackets for supporting offshore oil and gas facilities requires extensive computerised analyses to demonstrate compliance with recognised codes of practice. To perform these analyses, software is available which requires from the user only the barest definition of the problem. The whole process of modelling the structure, sea loading and the non-linear response of the foundations can proceed automatically. This is followed by the mathematical solution of the problem, checks against the requirements of the code and re-sizing as necessary. A successful structure is represented as a list of stress ratios less than unity. Any reasonably well-conditioned, triangulated space frame can survive this process, but by its very nature it cannot ensure that the most efficient and economical jacket is thereby produced. By adopting the approach that the computer should only be used to verify a design whose basic form is determined by the application of simple basic rules of structural detailing, it becomes possible to regain control of the design process and to lead it towards an optimum solution. The adoption of this approach to design a jacket for quite specific service conditions has led to a new configuration which, in providing solutions to situations beyond the initial application, can be considered generic.

Introduction
The simplicity and evident economy of early jacket designs for shallow water are desirable features to retain when such structures are developed for deeper water and more onerous service conditions. In the North Sea, this development was accompanied by a change in the installation method from lifting to launching, and the basic structural form was so drastically modified that continuity with shallow water designs was not appropriate. The subsequent development of derrick barges with crane capacities sufficient to lift-install jackets which hitherto had been launched makes it possible to reestablish this continuity. However, to a very large extent, liftinstalled jackets for deep water were developed from their launched predecessors, rather than from shallow water lified precedents which, in principle, should provide a more fruitful starting point. This paper will show the development of a jacket design which is based on a shallow North Sea structure, but extended so it can operate at the limit of a deep-water jack-up drilling rig (about 100 metres), and can then be further stretched to even deeper water. When the jacket is stretched so that it can no longer be lified using available derrick barges, the design lends itself to piecemeal installation without extensive modifications, the size of each piece being varied to suit the available lifting capacity.

Properties of Shallow Water Jackets
Fig. l(a) is a side elevation of a typical jacket suitable for a water depth of, say, up to 40m. The legs are vertical and spaced on a square pitch of 20-22.5m. It probably carries a deck weighing 500- 1000 tonnes and supports 5–10 well conductors which are accessed by an adjacent jack-up drilling rig.
Hibernia: Pioneering a new frontier
Authors: Smith Harvey A. 
Published: October 2008

Abstract
Hibernia is the pioneer development for the emerging Canadian east coast offshore oil industry. As the first operator in this area, the Hibernia Management and Development Company Ltd. (HMDC) is developing local skills and infrastructure which can support future developments. The Hibernia field is located 315 kilometres east southeast of St. John's, Newfoundland. It consists of two reservoirs - the Avalon and the Hibernia reservoirs, located at average depths of 2400 metres and 3700 metres respectively. Containing approximately three billion barrels of oil in place, Hibernia is the fifth largest discovered oil field in Canada. Recoverable reserves are estimated to be 615 million barrels. Limited data is available on the Avalon reservoir at this time, and initial drilling activity is expected to identify significant reserves upside. A fixed drilling and production platform is being assembled in Newfoundland to produce the field. Its design includes a first-of-its-kind concrete Gravity Base Structure, which has a 15 metre thick ice belt that can withstand the impact of multi-million tonne icebergs. The completed platform is scheduled to be towed to its offshore location in June 1997, with first oil expected in December. The platform has a design production capacity of 150,000 barrels of oil per day. Average production of 135,000 barrels of oil per day is expected during the 6 year plateau period. Other discoveries around Hibernia offer the opportunity for subsea tiebacks for processing and storage of crude in the future. Hibernia has a pre-production budget of US$4.4 billion, and total development costs are estimated to be US$8.0 billion, excluding transportation costs.

Introduction
The waters off the east coast of Newfoundland are host to 16 undeveloped oil fields containing estimated recoverable reserves of 25 1 million m3 (1.6 billion barrels). The area also contains an estimated 234 billion m3 of gas, and 58 million m3 of natural gas liquids1. With oil in place estimated at 477 million m3 (three billion barrels) and recoverable reserves of 98 million m3 (615 million barrels), Hibernia is by far the largest discovery offshore Canada to date. In fact, it is the largest undeveloped oilfield in Canada, and by the turn of the century is expected to produce approximately 10% of Canada's light crude oil production. Once Hibernia begins production in December 1997, it will be leading the development of a new offshore oil industry for Canada.
However, one field does not constitute an industry. In order for an industry to evolve, Hibernia has to prove that it can compete with similar operations by achieving its goal of top quartile industry performance in relation to the North Sea. This goal is achievable but will present challenges, especially in the area of platform support costs.
Using present day technology, it will take 18 years todeplete the estimated 98 million m3 (615 million barrels) of recoverable oil from the Hibernia field.
Research Issues in the Repair of Composite Structures
Authors: Donaldson S.L. , Song J.Y. , Roy A.K. 
Published: October 2008

Abstract
The composites repair in the past was mostly for nonstructural applications. For the present emerging systems and to extend service life of structural members, repairs need to be made at the structural level. Several issues that are imuortant to bonded composite repair and its performance in realistic environmental conditions are discussed, Some of the recent work performed at the Air Force Materials Directorate is presented. The effects of surface preparation and laminate stacking sequence on strength of double-lap shear specimens are described.

Introduction
The Air Force maintains a number of composite aircraft, and these numbers will increase in the future. Maintaining these aircraft will require extensive repair of damaged composite structures during their operational lifetimes. AS a result there is an urgent need for developing durable and cost effective repair methodology. The existing repair techniques usually use monolithic or composite materials as patches. doublers. etc., which are applicable for the repair of secondary structures and for small strain levels. But the present advanced aircraft, e.g., F-22, B-2, use a significant amount of composite structural parts and operate at higher strain levels. In order to maintain these advanced aircraft, there is a need to develop repair methodology for significantly higher strain levels.
The bolted and bonded repairs are both feasible repair techniques. But, the bolted joints in general weigh more than the bonded repair, and the holes created for the bolts also cause undesirable stress concentrations in the parent structures. Due to the availability of high performance and damage tolerant structural adhesives, the bonded repair is preferred over bolted. Thus issues related to the bonded repair will be emphasized and addressed in this project.

Research Issues
The structural performance of a bonded joint repair greatly depend on the performance of the adhesive that is used in the joint. The durability, damage tolerance, environmental effects, thermo-mechanical fatigue performance, etc. of a bonded joints are not yet well investigated. Of particular concern is the combined effects of repeated moisture exposure and drying cycles, in conjunction with thermal spiking and mechanical loading. Quite often repair (patching) requires to be performed in the field and on aircraft. The equipment availability in field repair is different from that performed in depot. But large and structurally reliable repair in the field must be performed to reduce down time of aircraft.
In the past repair used to on nonstructural parts, often small and easy to do. For the emerging aircraft systems and to extend life of existing aircrafts, repairs need to be performed on structural members and the repaired part should be able to reliably perform around a strain level of 5000 microstrain. As a result, there is a need for new repair materials, processes, analyses, and nondestructive inspection (NDI) techniques