bluuebunny/crossref_metadata_2025_split huggingface dataset:
Correcting for Vector Infidelity With OBS Data: From Ugh to Aah !
Authors: Clarke R.A. , Dellinger J.A. 
Published: October 2008

Abstract
Vector infidelity is the failure of ocean-bottomseismic geophones to respond isotropically to incoming seismic energy. With the rising popularity of multi-componentocean bottom seismic data, the issue of vector infidelity is becoming increasingly important. There are numerous causes of vector infidelity, which may be due to seafloor conditions, acquisition equipment or even processing.
We illustrate this with a catalogue of examples, highlighting the effects on the data and the final processed image, and we present some techniques to correct for these infidelities.

Introduction
Traditional marine seismic acquisition, using streamers of hydrophones, only records the pressure field at the receivers. Ocean bottom seismic acquisition, on the other hand, typically uses four component sensors in order to record the full wavefield at the receivers. While this provides moreinformation about the true elastic nature of the earth, it also leads to more a complex processing flow.
One of the first steps in this flow should be to correct for possible vector infidelity in the data. This occurs for numerous reasons. The cable or node is physically located on the seafloor so that the seafloor itself is a cause of vector infidelity. Spatial variations in the seafloor conditions can alsolead to variable coupling, and may cause a cable to lay in an odd position. For example, a rock could cause the cable to be twisted, leading to orientation errors, while a small hollow could cause the geophone to not be in contact with the seafloor at all.
As the cables are layed down they twist slowly, so thatthere is not usually a preferred top and bottom. Typically the geophones are gimbaled such that the vertical component remains vertical. This gimbal is very similar to a heavilydamped pendulum. However, because the gimbal can move, even though it is heavily damped, it often leads to crosstalkbetween the horizontal and vertical components, which shows up as converted wave energy on the vertical component. Fixed geophones may help reduce this, and would be cheaper to manufacture, but would add further complications to the processing.
The geometry of the cable also leads to vector infidelity. The cable is stiffer in the in-line direction so the in-line component of the recorded data usually has a higher frequency content. The coupling is typically better in the in-line direction than in the crossline. There is also evidence that cables mayroll when struck by the seismic wavefield, and the resulting motion is then superposed on the data of the crossline component.
These considerations, combined with the difficulties of placing cables in areas where the seafloor may be crowded, have led to recent interest in node technology. Nodes have more isotropic geometries and so should have fewer vectorinfidelity issues than cables. However, there may still be problems with coupling, and also problems due to the gimbals, so it is likely that a vector fidelity correction will still be needed.
Typhoon Steel Catenary Risers: As-Built Design and Verification
Authors: Thompson H.M. , Grealish F.W. , Young R.D. , Wang H.K. 
Published: October 2008

Abstract
The Typhoon 18" Gas Export Riser has the lowest water depth to diameter ratio of any installed riser to date, resulting in an extremely challenging fatigue design at the seabed touchdown point. Uncertainties related to the analysis and design of SCRs are particularly highlighted for this riser because the fatigue life is so close to design limits. This paper describes the as - built design of the riser by Stress Engineering Services (SES), and the as -built verification performed by MCS International. Even after the two analyses incorporating as-built field data were completed, the design and verification results showeddifferences that put the design either above or below the target fatigue design life. Areas of similarity between SES and MCS analyses are first described, including cross section modeling, TLP motions and offsets, hydrodynamic coefficients, S-N curves, and fatigue damage calculation method. Next, the primary areas of difference between the SES and MCS analyses are described, including touchdown point modeling and 3D drag linearization. Discussion of the state of practice of touchdown point modeling as it relates to SCR fatigue calculation is given. The paper concludes with a summary of lessons learned during the design and verification of the Typhoon SCRs.

1.0 Introduction
The Typhoon Field is located in Green Canyon Block 236 and 237 in approximately 2,100-ft water depth. The TLP is owned y BHP and ChevronTexaco, with ChevronTexaco the designated operator. The discovery well was drilled in April, 1998 and the project sanctioned in January 2000 for the development of 4 subsea wells produced to a centrally located TLP. Flexible risers are used for the production wells. A 10" oil export SCR and 18" gas export SCR are used for product export.
The verification section of this paper will focus on the 18" gas export riser. At the time of installation the 18" gas export riser had the smallest water depth / diameter ratio of any installed SCR, resulting in an extremely critical fatiuge life at the SCR touchdown point.

2.0 As-Built Vs. Design by Stress Engineering

Design
Stress Engineering Services (SES) was part of the Typhoon SCR design team and was responsible for the design analysis including initial sizing and detailed analysis for environmental conditions. The analysis provided design parameters including SCR shapes, extreme and cyclic loads for designing the SCR porches and flex joint receptacles, and extreme and cyclic angles for designing the flex joints. Fatigue analysis not only provided an evaluation of the expected life of the SCR's but it also identified target SN curves to be qualified by testing of the welds and provided histograms of stress ranges for the fracture mechanics analysis used to establish automatic UT (AUT) acceptance criteria for the actual installation welds. The fracture mechanics analysis was performed by Hsu (February, 2001).
Low Cost Anchor System for Flexible Risers in Deep Waters
Authors: Medeiros C.J. 
Published: October 2008

Abstract
In order to avoid that the loads generated by the floating units movements be transferred through flexible risers to subsea equipment, significantly additional flow lines length have been used to absorb those loads by line/soil friction. Due to the high costs of these lines, Petrobras has developed a new anchor system concept to fix the risers on the seabed, in lieu of increasing flow lines length. This anchor system, called "Torpedo", consists of a pipe pile filled with scrap chain and concrete, close ended with a cone tip, installed by free fall from a vessel, and connected to the risers with a special system operated by ROV. Bundle of three risers have been anchored by each pile with holding power of 1400 kN.
Taking advantage of the experience in this pile design and installation to anchor risers, larger free fall piles with holding power up to 7000 kN have been designed and already certified to anchor floating units.
This paper aims to present an overview of the design and installation procedures, cost estimation, field and model tests results and applications of the Topedo Anchor System.

Introduction and Background
Flexible risers are anchored on sea bed by means of drag anchors or plates, gravity structures and piles which may be installed by driving, suction or drilled and cemented in.
Because of the high costs of these anchoring method for deep water, since 1996 Petrobras has developed the technology of free fall piles to be installed in soft clay to anchor flexible risers and floating structures.
To evaluate the costs and performance of this solution, in house softwares have been developed and full scale in situ tests have been performed in Campos Basin (see Fig. 1). Model tests (see Fig 2), with different weights and shapes were made in laboratory, in order to optimise the torpedoes design.

Torpedo Anchor Characteristcs
The torpedoes designed to anchor flexible risers is a 30" OD pipe pile, twelve meters long, filled with scrap chain and concrete (see Fig. 3). It has a dry weight of 240 kN and a holding capacity of 1400 kN. The pile/mooring line connection has an internal padeye underneath a guide that allow the anchor load to be applied in any direction. With these characteristcs, it has been used to anchor a bundle of three risers up to 12" of diameter in 1300m water depth.
Torpedoes Anchors with that same 30" OD tube twelve meters long, ballasted with heavier material and provided with four vertical fins (0.45 m × 9 m), are being fabricated to anchor MODU's (Fig. 4). To anchor Floating Production Systems (FPS) with a required holding capacity of 7500 kN, torpedoes designed with 42" OD tube, fifteen meters long, dry weight of 950 kN, and provided with four vertical fins (0.90 m × 10 m), are being manufacturated.
The Accident of P-36 FPS
Authors: Barusco Pedro 
Published: October 2008

Abstract
The semi submersible platform P-36 was operating in Roncador Field, in Campos Basin, producing 84.000 bopd, with capacity to reach the peak production of 180.000 bopd. On the 15th of March of 2001 an accident took place on board of the unit causing the death of 11 crewmembers and the sinking of the platform five days later.
An inquiry commission was formed just after the accident in order to investigate the causes and set up recommendations in order to prevent similar events.
This paper describes the methodology applied by the commission during the investigation phase, the work developed by them, what happened on board on that day, the conclusions about the main causes which led to the sinking of the unit and the recommendations addressing design, operation and safety of floating offshore units.
The results, conclusions and recommendations relative to this accident were used by Petrobras as bases to create a program inside the company called Operational Excellence Program whose main goal is to implement several actions toward increasing of the safety of offshore operations.
As for Petrobras, the information disclosed in this article can help other oil companies improve their HSE programs.
The detailed description of the events which took place the moment of the accident until the sinking, the main causes, conclusions, observations and recommendations of the inquiry commission and a general picture of the content of the Operational Excellence Program of Petrobras are addressed by this article.

Description of the P-36 platform
The P-36, formerly called "Spirit of Columbus", was a floating production unit (FPU) based on a conversion of a Friede & Goldman L-1020 Trendsetter type semi submersible platform. It was initially designed and built, in Italy, as a FPU to operate at 500m water depth, with a capacity to process 100,000 bopd and 2 million cubic meters per day of gas. The design and construction began in 1984 and ended in 1994.
The field, which it was intended to produce, did not prove to be commercial during the development phase. As a consequence it was offered to Petrobras that analyzed the possibility of converting the unit to produce in Campos Basin. After the evaluation for use in Marlin South and Roncador fields, Petrobras decided to select the unit to be the first FPU of the giant Roncador field.
The main modifications done during the conversion phase were: complete substitution of the process plant, installation of a new power generation plant, removal of the drilling equipment and propulsion system, changing the mooring system and increasing the payload by the addition of stability boxes in the pontoons and blisters in the columns.
After the conversion, which lasted from September 1997 to October 1999, the platform had the capacity to produce 180,000 bopd, to handle 7.2 million cubic meters per day of gas and could be installed at water depths around 1500m.
Roll Minimization by Blige Keels and Moving Weight Systems
Authors: Vassilopoulos Lyssimachos 
Published: October 2008

ABSTRACT
The objective in this paper is to discuss the technical and economic considerations arising in the process of minimizing the roll motion of marine vehicles through the use of bilge keels and moving weight systems .. Given a statement of the mission and owner';s requirements for any vessel, the procedure for selecting the most appropriate anti rolling device is delineated on the basis of a trade-off analysis among candidate systems for such an application. Design methods are developed for moving weight systems and bilge keels on the basis of linear and nonlinear mathematical models of the interacting ship-stabilizer motions. The paper concludes with the description of a computer program developed for stabilizer design, some example applications and a brief review of the economic advantages accrued by the incorporation of roll stabilizers.

INTRODUCTION
During the last decade, the maritime industry has witnessed an impressive trend toward the deployment of "roll stabilizers" onboard different types of marine vehicles. Contrary to what their name might imply, the function of such systems is to minimize or suppress a vessel';s roll motion, rather than enhance its transverse stability. Typical anti rolling devices range from the time-honored bilge keels to sophisticated fin arrangements and activated tanks, each providing a differing roll reduction effectiveness depending on the particular application.
Unlike other ship motions, roll is readily susceptible to containment, mainly because the inherent damping properties of most hulls are low and also because the external couples acting on the vessel are not too excessive. Under such conditions, it becomes relatively easy to conceive of a system that produces, at the expense of a small amount of energy, the appropriate torque counteracting that induced by the environment. The required energy may either be extracted from the rolling vessel itself, as in the case of passive anti rolling systems or may be supplied externally by separate sources, as in the case of activated devices.
The question of whether a given vessel should be equipped with one or more anti rolling devices cannot be answered objectively unless a study is made of her dynamic behavior in the expected environment, given the mission objectives and hull characteristics. The first step in such a study is to attempt to define critical measures of roll (or its time derivatives) which can be used as yardsticks of what constitutes acceptable roll behavior, Ref. (1). The second step is to find how the vessel behaves in a variety of operational conditions and to judge whether her responses are acceptable. If they are, the question of stabilization is by-passed. If they are not, the third step is to examine whether certain changes in geometry and mass distribution might reduce roll.
Girassol: The FPSO Presentation and Challenges
Authors: Bang Pierre 
Published: October 2008

Abstract
While the history of floating production storage and offloading (FPSO) is paved with record cost overruns and delays, through the description of the Girassol FPSO project, this paper presents the ways and means used by the Operator-TotalFinaElf - to manage the successful development of the world's largest deepwater FPSO installed in the Girassol field, offshore Angola.
The Operator, in developing the FPSO, employed parallel engineering, functional specifications and an early involvement of the industry with an original contracting strategy in order to achieve the Girassol field development in less than six years from discovery to first oil setting a new standard for the Industry.
The FPSO described here is now the only visible facility of this pioneering project for the offshore industry (Figure A-1).

Introduction
Discovered in April 1996, the Girassol field development was sanctioned two years later in July 1998 based on a subsea production scenario associated with a large FPSO, having the following main characteristics:Oil storage: 2,000,000b/dOil Production: 200,000b/dLiquids treatment: 300,000b/dProduced water treatment: 180,000b/dWater Injection: 390,000b/d at 150 barSeawater Sulfate Removal : 400,000b/d &lt; 40 mg/lGas injection: 8,000,000Sm3/d at 285 bar
On December 4, 2001 the world's largest FPSO produced first oil from subsea wells through a subsea production system (SPS) and umbilical flowlines and riser towers (UFL) from the 1,400m water depth at the Girassol field.
Sailaway of the FPSO from the construction yard in South Korea occurred at the end of March 2001 at a level of completion and commissioning never achieved before for a production unit of such complexity. The completion, just 33 months after the award of a contract based on functional specifications, constituted a new benchmark for future FPSO's. The hull construction subcontract was performed in 19 months and the construction of the 25,000tonnes topsides subcontract was done in 21 months.
The initial "fast-track" approach of the Girassol development required the FPSO execution to face the following challenges :Parallel reservoir engineering and surface facilities development;Interface data issues due to different schedule in design development between UFL and FPSO;Management of significant design data changes in throughput and treatment capacity during contract execution;
Additional challenges to the FPSO development came from the following adverse events which occured during the course of the project execution:Very buoyant shipyard market;Reallocation of topsides construction and integration site.
From the first months after discovery, the Girassol FPSO development history described here presents how the Operatorand its Contractors, through the contracting strategy, the main architectural choices and project execution, faced these challenges and managed the successful FPSO development, crowned by first oil 41 months after project sanction.
Modelling Risk and Safety Systems of Deep Offshore FPSO/Pipeline System
Authors: Abhulimen K.E. , Susu A.A. 
Published: October 2008

Abstract
This paper presents a model that captures the risk and safety systems of a deep offshore FPSO/Pipeline system. The overall risk and safety function of the FPSO/Pipeline system was hierarchically determined as a universal set of sub risk systems, using a modified fault tree analysis and FMECA (Failure Mode Effect Critical Analysis) to establish the cause of failure and evaluate its potential. The transient state behaviour of the risk and safety systems of the FPSO/Pipeline system was modelled using the markov chain process. The results of simulation of a typical FPSO-Pipeline sub system, shows that a model suitable for analysing the risks and safety behaviour of complex multifunctional FPSO/Pipeline system has been developed. The inclusion of a weighting function in the model to assign a relative importance of a risk or safety event in several interacting risk systems represents an important deviation from other benchmarks. The concept of weighting function relies on the experience of the user to assign different weights to different risks or safety in a given environment. This allows the possibility of evaluating the impact of different risks on the reliability of multifunctional systems

Introduction
There are many methodologies proposed for reliability, risk and safety analysis for most, if not all process industries known today. Among the most popular ones, are quantitative risk analysis, probabilistic safety analysis, and worst-case methodology for risk assessment and optimal risk analysis. The optimal risk analysis (ORA) appears to be the most suitable, as it is fast, less expensive to implement, less time consuming and more precise than alternative analysis (1, 2). ANSI/ISA S84.01-1996 is the consensus standard for process safety in the U.S, deemed to meet the OSHA 1910.119 PSM regulation (3).
Three methodologies are proposed in the TR84.02 report to be published by ISA (4). They are simplified equations, Fault Tree Analysis, and markov modelling to implement the safety performance requirements of the standard, for the SIS. The standard requires that the average probability failure on demand (PFDavg) be used in this analysis (5,6).
Khan, F.I, and S.A Abassi (1) have presented a critical review of these methodologies. While the benefits of these methods have been well demonstrated in many publications, it appears that the development of a model that captures the intrinsic behaviour of the risk and safety systems of typical complex multifunctional system like the FPSO/Pipeline system have not been sufficiently researched. The problems are normally associated with complexity of the interacting components and process hazards that could lead to failure (7).
Our paper therefore, presents a model that incorporates the use of a weighting function to capture the complex risk and safety behaviour of the interacting components of the subsystem of typical FPSO/Pipeline system. A common misconception is to assume that a system prone to fewer risks is safe.
An Overview of the Na Kika Flow Assurance Design
Authors: Hudson J.D. , Dutsch D.B. , Lang P.P. , Lorimer S.L. , Stevens K.A. 
Published: October 2008

Abstract
The Na Kika project is among the most complex subsea developments attempted by our industry and faces a number of unique flow assurance challenges due to the extreme water depth (5800 to 7600 ft), distributed well layout, variability in produced fluids (from six distinct fields), offsets of up to 26 miles and relatively low temperature reserves. Flow assurance provided key drivers to subsea system selection and definition and was an important aspect of assessing project profitability. This paper gives an overview of well and subsea system features and describes the flow assurance strategies and the unique operations that will be required for successful operation at Na Kika.

Project Characteristics
The Na Kika project consists of six oil and gas fields in the Mississippi Canyon area of the Gulf of Mexico. Water depths range from 5800 to 7600 ft. The individual fields in the Na Kika base development are Ariel, Kepler, Fourier, Herschel, and East Anstey, each of which will be developed as subsea fields with produced fluids routed back to a floating host roughly located in the center of the development area. Coulomb is currently being developed as a near-term addition of reserves, which will likely be produced by a single flowline back to the Na Kika processing facility. Offset distances from the host are in the range of 5 (Ariel) to 26 miles (Coulomb). The general arrangements are as according to Figure 1.
The Na Kika subsea layout consists of a single, 10" × 16" pipe-in-pipe flowline loop for those fields north of the host (Ariel and Kepler), as shown in Figure 2. On the south side, there are two flowline loops, an 8"x12" pipe-in-pipe insulated oil loop for the Herschel and Fourier wells, and an 8" uninsulated gas loop for the East Anstey and Fourier wells (see Figure 3). The subsea system at Fourier includes the flexibility to allow the clustered wells to produce back through either the gas or the oil flowlines, via well jumper reconfiguration. This subsea architecture deviates significantly from previous projects through the use of flowline loops, as opposed to dual lines to a manifold, and the use of a single flowline for the relatively rich Coulomb gas wells.
The key input into the flow assurance process is the proper acquisition and analyses of fluid samples. In the case of system selection for Na Kika, fluid samples are available from at least one exploratory well from each of the individual fields and, in the cases of Ariel and Fourier, from subsequent appraisal wells. The analysis of these samples has been used in the flow assurance work described in this paper. There remain, even at this point, some uncertainties about key fluid properties, such as salinity and asphaltene stability. These uncertainties have been considered in the analyses and have been used as a basis for future sampling efforts for the development wells.