bluuebunny/crossref_metadata_2025_split huggingface dataset:
Background and Status of the FPSO Fatigue Capacity JIP
Authors: Lotsberg Inge 
Published: October 2008

Abstract
A joint industry project on the Fatigue Capacity of FPSOs is being carried out with 19 participants from oil companies, designers, shipyards, classification soceieties and one university. This paper presents the background and the status of the project. The main objective of the project is to reduce the risk for fatigue cracks and fracture in FPSOs.
Part of the work is carried out by a number of participants as work in kind.
The project will provide small scale and full scale S-N data on typical fatigue sensitive details in FPSOs and tankers. It will also provide improved information on the important link between S-N data and finite element analyses for fatigue life assessment. Finally it will provide data to assess more reliable the risk for unstable fracture of FPSOs when fatigue cracks are present in the structure.

Background
In offshore oil production there is a trend towards Floating Production, Storage and Offloading Units (FPSOs), either on the basis of converted, used tankers or as newbuildings with a typical tanker structure. Experience from tankers built in the seventies and eighties have shown that especially the side longitudinals have been susceptible to fatigue1,2. Based on this experience the classification companies have introduced more strict fatigue requirements for tanker design3–7.
Various FPSO units are now entering the North Sea and other harsh environments, such as the North Atlantic. FPSO units can be deployed in marginal fields, at remote locations and in deep water. A clear advantage with these units is storage of oil, possibility for relocation and rather early production. Fatigue cracks may lead to stop of the field production, which can hardly be tolerated. Early fatigue problems must therefore be avoided, as a repair during service life might be very costly when cost of lost production is considered. Therefore it has become more important to assess the fatigue life of an FPSO at a design stage in a more reliable manner than was considered necessary for sailing ships where fatigue cracks might be repaired as part of a normal maintenance program.
Design requirements to fatigue of tankers have to a large extent been developed based on service experience. Floating production units have also been in service for several decades, but the concept of the permanently turret-moored tanker is relatively new. Most of the FPSOs in service have still to prove that they can meet the expectations regarding their fatigue life performance, as the majority of them have been in use for less than ten years.
Nowadays sophisticated analysis methods are available for fatigue life predictions of details of FPSOs. However, the reliability of such analysis is significantly depending on the fatigue capacity of the considered details (S-N data) used as input. Therefore it is considered important to reduce the uncertainty associated with the S-N data that are being used for design of typical ship details in order to improve our confidence in the analysis procedure used to calculate the fatigue capacity of these details8–10.
An Analysis of Discover II Motions and Mooring Line Forces
Authors: Sisk James M. 
Published: October 2008

Abstract
This paper covers the performance of the drill ship, Discoverer II, while it was working in severe sea conditions in the Bass Straits of Australia and off the west coast of New Zealand. Motions and mooring line tensions for various sea states are presented. The maximum sea conditions in which the vessel has worked are also presented. The novel, special features, and benefits of the mooring system are discussed.

Introduction
Ship motions, mooring line tensions and weather conditions have been recorded on the floating drill ship, Discoverer II, since it started drilling in May of 1968. An extensive study has been made of these records to evaluate the performance of Discoverer II under severe operating conditions.
The main objectives of this study were:
1. To obtain information which can be used to predict vessel motions and anchor line tensions under various sea conditions.
2. To determine the maximum sea conditions under which the various drilling operations can be performed.
3. To compare actual motion data with model data.
A Study of Different Flared Joint Configurations
Authors: Bouwkamp J.G. , Vaish A.K. , Terata H.G. 
Published: October 2008

ABSTRACT
The paper deals with the stress distribution of flared tubular joints typically encountered in off-shore platforms and semisubmersible oil drilling structures. Stress results of an analytic computation treating the structure as a thin shell and using a finite element approach have been presented for an axial load condition and compared for the following four configurations: namely, a flared joint without any stiffeners, a flared joint with a ring stiffener at the junction between tube and flared portion, a flared joint with four cross-stiffeners (cruciform), and a flared joint with four cross-stiffeners and a ring stiffener.
The analytical results for the non-ring stiffened joints have been compared with results obtained experimentally. The study indicates the effectiveness of the cruciform gusset plate in reducing the shell stresses in general. Ring stiffeners are instrumental in achieving a more uniform force transfer and in reducing the stresses in the critical joint regions.

INTRODUCTION
With the increasing emphasis on large Size diameter column members for both semisubmersible drilling units and drilling platforms, the design of the connection between the brace members and the column member has received considerable attention. A possible direct jacket-type connection is ruled out economically because of the requirement that the column wall thickness should preferably be equal to 4.5 per cent of the outer-diameter of the columns*. Amore appropriate solution is obtained by creating a load transfer through in-plane gusset plates. Another commonly used design incorporates external wing plates or so-called flared jointst2,3). In the latter cases, the intent is to spread' the branch member loads over a larger portion of the column member and to reduce the often critical local bending stresses in the column wall. This solution represents in effect an increase of the d/D ratio, i.e., ratio between the outer diameters d and 0 of the branch and column members respectively, and undoubtedly improves the state of stress in the column wall. However, unfortunately, both solutions inherently cause the development of stress concentrations in the branch member wall at either the tip of the wing plates or at the junction between the tubular section and the flared portion of the branch member. Because of the increasing use of flared connections, the paper deals with a study of the basic load transfer into the flared section as influenced by both ring and cruciform stiffeners. Because of the fundamental aspect of this study, a simple model consisting of a circular tubular section and a flared portion has been selected. The actual junction between the flare and the column has been omitted since the load transfer in that connection is in general less critical. The load condition selected for this basic model is a pure axial compressive load.
The tubular joint under load approximates in structural behavior to a shell; i.e., the load is taken by the geometrical stiffness in addition to the material stiffness.
Deep Water Gulf of Mexico Sea Floor Features Revealed Through 3D Seismic
Authors: Scott E. , Peel F. , Taylor C. , Bryant W. , Bean D. 
Published: October 2008

Abstract
The Gulf of Mexico sea floor has been mapped with a variety of different methods with varying resolution. Until recently higher resolution 3D seismic surveys have generally been limited to site specific localities. With hydrocarbon exploration advancing and evolving, larger 3D seismic surveys have been acquired and are now available on a regional scale.
Mapping of the sea floor reflector on a regional 3D seismic data set in the Green Knoll/Walker Ridge area has resulted in a higher resolution map than previous data sets. The seismic data has revealed a set of regionally extensive furrows, a previously unknown Gulf of Mexico sea floor feature. Preliminary investigations show that the erosive style of the furrows change in a predictable pattern in conjunction with an increase in current flow velocities. The erosional features of the furrow field indicate the presence of strong ocean bottom currents.

Introduction
A variety of methods during the past few decades have been used to map the sea floor in the northern part of the Gulf of Mexico. Until recently, the highest resolution data sets with the most extensive coverage have been surface-towed, multibeam, side-scan-sonar (NOAA Seabeam) and long-range sonar (GLORIA). Maps from these data sets, such as those produced by Jia Liu and William Bryant1, have approximately a 30 meter resolution on the sea floor (Fig. 1). However, in deep and ultra-deep water depths the resolution is lower due to the greater travel time from source to receiver.
Other data sources that have been used to generate sea floor maps of the Gulf of Mexico include gravity, magnetics, satellite sensors and 2D seismic surveys. While maps generated from gravity, magnetics and satellite data cover the whole of the northern Gulf of Mexico or over a larger area, they are of much lower resolution than either the NOAA or GLORIA data. 2D seismic data provides a higher resolution of the sea floor, but due to their nature of a lattice of separate lines, they lack the spatial resolution to define subtle features on the sea floor.
As seismic acquisition and processing technology evolved, 3D seismic surveys became available. With the close spacing of data points, 3D surveys provide greater spatial resolution to map the sea floor and illuminate subtle features. However, due to cost and technological limitations, the first surveys were restricted to site specific localities with small areal extents. With the increased spatial resolution these initial surveys provided a more detailed map of the sea floor but only represented a postage stamp look in a regional context of the northern Gulf of Mexico. With the recent advances in technology along with exploration for hydrocarbons advancing to deep and ultra-deep water, larger 3D seismic surveys have been acquired and are now available on a regional scale. With the availability of these regional surveys, sea floor features that were previously unrecognizable have now been identified.
Hydrate Formation from CO2 and Sea Water
Authors: Makogon Y.F. , Holditch S.A. 
Published: October 2008

Abstract
Carbon dioxide (CO2), which is one of the most abundant compounds on Earth, is present in rock, the oceans and the atmosphere. CO2 influences many biological and dynamic processes. Carbon dioxide is very soluble in water due to its high dipole moment. Solubility of a gas in water is dependent upon the temperature and pressure. This dependence affects the changing content of gases in the atmosphere, and the variable effect that certain gases have on the climate. Currently, many believe that the effect of CO2 on global warming exceeds 50% of the combined effect of all greenhouse gases. CO2 is present as a gas, or can be dissolved in water, or can be found in a solid state. CO2 can also exist in a solid state as a clathrate hydrate.
Gas hydrates are known as metastable minerals, whose composition and properties are determined by the source components, temperature and pressure. Knowledge of the conditions of formation, stability and decomposition of CO2 hydrate with seawater and the mass ratios of gas and water during phase transition appears quite important. In this paper, we present the results of laboratory work concerning the kinetics and morphology of a CO2 -seawater system at pressures up to 50 MPa and temperatures of 268–295 K. Measurements of CO2 solubility in supercooled seawater before and after hydrate formation are discussed. The conditions of CO2 hydrate formation and stability in seawater that is under-saturated with gas are described. The research results reveal a number of details concerning hydrate formation and dissociation, including the limits of dissolved gas in water for stable conditions of gas hydrate crystals in the water volume. Also, the information can be used to interpret the role of gas hydrates in the global changes on our planet. The results of this work permit to determine the most effective technologies to control the content of CO2 in the atmosphere. We cannot include all of our results in this paper, due to the volumes of research data generated on this subject. However, many of our most important findings have been included and discussed.

General Information About The CO2 And Seawater Used In This Work
The following gas and liquids were used during the experiments.

Gas:
Carbon dioxide (99.9% CO2 + 0.04% CH4+ 0.06% N2)

Liquids:
Salt (sea) water - standard laboratory mixture containing 41.953 g/L sea-salt composition (meets American Materials Standard D-1141-52 Formula A) mixed with distilled water.
Table 1 presents the composition of the sea salt used to mix the synthetic seawater.
The density of the seawater that we mixed in the laboratory was 1.025 g/cm3 at 15 °C. Of course, the density of seawater will depend upon the temperature, pressure and salinity of the liquid. For atmospheric pressure, the density of seawater as a function of temperature and salinity is illustrated in Figure 1 (improved, from Sea Water: Its Composition, Properties and Behavior).
Hoover/Diana: Topsides
Authors: Milburn Frank H. , Williams Ron  H. 
Published: October 2008

Abstract
This paper covers the design and construction of the Diana/Hoover Topsides. A description of the facility covering capacity, major equipment, and environmental parameters is outlined. Design issues such as safety considerations on a floating platform, ABS certification, installation considerations, the impact of motion on process facilities, and methanol recovery are addressed. The Safety Management Philosophy is described. The paper concludes with an overview of the key success factors for the project.

Description of Production
The Diana field is composed of five subsea wells located in East Breaks 945, 946, and 989. The wells were drilled and completed with a Mobile Offshore Drilling Unit (MODU). The Hoover field is located in Alaminos Canyon Blocks 25 and 26, and the dry tree wells are being drilled and completed with an API Platform drilling rig installed on a Deep Draft Caisson Vessel (DDCV). The Hoover rig was refurbished and modified to withstand DDCV motions and perform operations not commonly performed by API platform rigs such as drilling and production riser installation and removal.
The Diana Subsea development is located fifteen miles west of the Hoover host facility in a water depth of approximately 4500 feet. The Subsea development consists of a northern drill center (NDC) and a central drill center (CDC).
The NDC is connected to the Hoover host facility via a single 10" production flowline and the CDC is connected to the Hoover host facility via one 10" and one 6" flowline. The manifolds are connected to each other by a three mile 10" infield flowline. The 10" flowlines serve as the primary production lines, while the 6" performs as a production line as well as a test line when required. Flowline and manifold configuration enables well testing capability of all subsea wells and loop pigging of all three of the flowlines.

Processing Facilities
The Hoover/Diana process facilities are represented in a simplified manner in Figure 1. General data for the topsides is given in Table 1. The design philosophy was to use the tried and true wherever possible and get operator input from the beginning. Mustang Engineering, Inc. was the primary topsides facility designer.
The initial process flow for Diana subsea production is heating, pressure reduction through a choke, and flow into the HP production manifolds at approximately 1100 psig. Local Hoover production flows into the IP or LP separator headers atapproximately 530 or 180 psig respectively.
Produced water dumping from the LP Separator flows through hydrocyclones and a vertical flotation unit prior to overboard discharge through a subsea diffusion pipe attachedexternally to the hull.
Each pressure system has a horizontal separator. Gas from each pressure system flows to the appropriate compression stage suction scrubber. Hydrocarbon liquids and water fromthe HP and IP separators flow through hydrocyclones, where the water dumps to a methanol recovery process. Oil then dumps to the next lower pressure separator stage.
World-Record Horizontal Trees for Diana
Authors: Deeken David , Towns Keller , Johnson Jess , Kenny J.P. , Skeels Brian , Vickrey John 
Published: October 2008

Abstract
From July 1999 through May of 2000, five horizontal subsea Christmas trees were installed in 4,750 feet of water in the Diana field in the Gulf of Mexico. The previous depth record for horizontal trees was about 3,400 feet. A wet parking scheme for tree installation was used to save money by reducing BOP trips and by using a less costly installation vessel. The final horizontal section of up to 1800 feet of the reservoir was drilled through the tree. Innovative techniques that saved time and money were used to contract, engineer, and test the tree, and bring the well on production. These techniques and lessons learned can be applied by others using horizontal trees in deepwater applications.

Introduction
The Diana and Hoover fields are located approximately 150 miles east of Corpus Christi and 160 miles south of Galveston, Texas, in the Gulf of Mexico. The Diana Field consists of East Breaks Blocks 945, 946, 988, 989 and Alaminos Canyon Block 21. Initial exploration of the area began in 1990 and two further delineation wells followed in 1996. The Diana reservoir features a slanted crescent-shaped formation with a thin oil rim along the down dip region. However, Diana's remote location and the extreme waterdepth of 4,750 feet made the field challenging. The discovery of the Hoover field (Alaminos Canyon Blocks 25 and 26), 16 miles away, provided additional incentive to develop the necessary infrastructure and co-develop both fields simultaneously.
Hoover would be produced from a deep draft caisson vessel (DDCV) (Figure 1) and the Diana field would be developed via subsea completions tied back to the DDCV. The Diana field consists initially of 5 oil wells that will be redrilled and completed higher as gas wells later in field life. Each tree is tied via a nominal 5" hard pipe U-jumper to one of two gathering manifolds (two at the northern drill center, three at the central drill center). The manifolds are in turn connected together in a daisy chain fashion by 10" hard pipe pipelines, in a round trip loop, to accommodate pigging. The pipelines extend back 16 miles to the DDCV, terminating in steel catenary risers (SCRs). Project timing permitted the Diana field to be drilled, completed, and ready for production when the DDCV was commissioned.

Systems Engineering And Trade-Off Studies
When work began in 1996 for Diana it was recognized that it would be deeper than the then-current subsea world record of about 3,300 feet. However, two vendors were building vertical tree (VXT) systems for water depths in excess of 5,000 feet. Both systems were installed in mid 1997. In addition, if a horizontal tree (HXT) were chosen, it would bein record water depths for an HXT. Consequently the two vendors building the deep water systems were chosen and paid for early trade-off studies for Diana. The results included their recommendations of HXT versus VXT, comparative specifications, procedures, and costs.
Stress-Controlled Porosity in Overpressured Sands at Bullwinkle (GC65), Deepwater Gulf of Mexico
Authors: Flemings P.B. , Comisky J. , Liu X. , Lupa J.A. 
Published: October 2008

Abstract
Porosities, calculated from wireline density logs, decrease from 33% to 30% over a vertical depth range of 1200 feet in the J3 sand of the Bullwinkle Field (GC65), Deepwater Gulf of Mexico. This 10% decrease in porosity results in a 58% decline in permeability (3.3 to 1.4 darcies). The spatial variation in porosity results in a 75% decrease in acoustic reflectivity over a depth range of only 500 feet. The decrease in porosity with depth is interpreted to result from compaction over geological time scales, which results from higher in-situ stresses at the reservoir low points than at the highpoints. The study provides an approach to predict the spatial variation of porosity and permeability expected in a homogenous, isotropic, and compressible reservoir. These rock properties are important parameters for reservoir simulation. The acoustic results imply that the reservoir will be imaged differently due to in-situ stress conditions alone and independent of changes in lithology or pore fluid.

Introduction
The Bullwinkle oil field is located on the western flank of a circular salt-withdrawal mini-basin on the slope of the Gulf of Mexico, approximately 150 miles to the southwest of New Orleans, Louisiana (Figure 1). The mini-basin is primarily located in Green Canyon blocks 65 and 109, in approximately 1350 ft. water depth (412 m). Holman and Roberston1 and O'Connell et al.2 describe the Bullwinkle field; Kikani and Smith3 describe the Rocky field which lies on the southeastern margin of the mini-basin.
The J sands are of early Nebraskan (3.35 Ma) age and host the majority of the reserves at Bullwinkle.1 The 5 sands (J0-J4) are bowl-shaped interconnected channel and sheet turbidite sands that are interbedded with debris flow deposits and shales, and overlain by a thick section (500 ft.) of bathyal shales. The top of the section is characterized by multiple erosional unconformities, suggesting a period of sediment bypass in the basin.1 Pressure drawdown at each well followed the same depletion curve, indicating that all the sands are in pressure communication.1,3
The J3 sand is located on the western flank of the minibasin (Figure 2). It is very fine-to fine-grained and has a blocky log character (Figure 3). The lithology and the grain size are relatively homogenous across the field. It is interpreted to be a ponded, internally amalgamated, sheet sand.1 There is a small oil and gas pool at its crest, while the majority of it is brine saturated (Figure 2). It has been penetrated by 23 wells.

Porosity Analyis in the J3 Sand
Whole core was taken in the J3 sand at the A-32-BP, which is beneath the J3 oil-water contact (Figure 2). In this well, density porosities (DPHI) correlate with whole core porosities when a fluid density of 1.05 g/cc and a grain density of 2.65 g/cc are assumed (Figure 4).