bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technical Challenges and Success for Deepwater Riser Wet Parking, Recovery and Transfer Installation In Frade Field
Authors: Wang Jun , Radan Ecaterina , Hagen Rune Krister , Bullock Jackson D. 
Published: July 2010

Abstract
As a contingency plan to decouple the Polar Queen installation from the Frade FPSO installation, 18 flexible pipe risers and 4 umbilical risers needed to be wet parked with tight field architecture, high and unpredictable bottom currents at Frade development field in Brazil. After turret FPSO was in place, all of the risers and umbilicals were recovered from 1065 m water depth and transferred to Frade FPSO. The FPSO turret slot arrangement makes the riser pull-in operation very challenging due to the nearby slot separation angle of only 3 degrees. However the entire recovery, transfer and pull-in operation was a success, finishing in 9 days (3 days ahead of schedule) without a single safety incident, or damage to equipment.
This paper will present the highlights of the technical challenges for riser wet park, recovery, transfer and pull-in installation operation from analytical and operational aspects, and how the main challenges (such as wet park curve, anchor clamp chain installation, riser recovery route, transfer depth, and interference risk assessment) were overcame. Heave velocity methodology was introduced in this project and became a key to success in application for the entire operation. Conclusion, recommendations and lessons learned will be made.

Introduction
Frade BV developed the Frade field located in the northern Campos Basin, 122 km offshore in water depth ranging from 1000m to 1,350 m with irregular sea-bottom. This included around an FPSO the installation of 36 flowlines, 18 flexible risers and 17 umbilicals.
Subsea installation activities began in June, 2008, and 36 flowlines had been successfully installed by December 2008. To decouple the FPSO installation from the Polar Queen installation, Chevron decided to wet park all 18 flexible pipe risers and 4 umbilical risers in the Frade Field, and to later recover and transfer to the Frade FPSO when it was in-place.
SS: Multibeam Backscatter - Insights into Marine Geological Processes and Hydrocarbon Seepage
Authors: Orange Daniel L. , Teas Philip A. , Decker John 
Published: July 2010

Abstract
By combining multibeam bathymetry and backscatter with accurately placed piston cores, and integrating these data with 2D multi-channel seismic and high-resolution sub-bottom profiling, we can gain a better understanding of the processes active in a marine basin. In addition on mass transport complexes, basin floor fans, slumps, and faults, we can identify and sample potential hydrocarbon seeps that provide direct samples of a petroleum system. This paper will examine features imaged during a large (400,000 sq. km.) survey carried out in Indonesia in 2006-2008.
Using hull-mounted systems, an average 1000 sq. km. of high resolution (25m bathymetric bin, 5m backscatter pixel) data were acquired per day in water depths from 100 to 3500m. Piston cores accurately placed on seafloor targets using USBL navigation were described visually on the coring vessel, sub-sampled for geochemical analyses, with the remainder of the core preserved for later analysis. Approximately 35% of the cores have been CT scanned, highlighting density differences related to seepage (such as authigenic carbonate and shell fragments), or related to sedimentological features (where higher density sand grains can be distinguished from lower density mud).
The cores, and the targets they analyzed, provide a catalog of anomalous backscatter features that have been ground-truthed to constrain the processes that created the features. Features such as basin floor fans, overbank deposits, upslope climbing mud-rich mega-dunes, sand-rich channel axes, drowned carbonate reefs, mud volcanoes, and chemosynthetic seeps have been sampled throughout the program. This catalog demonstrates that backscatter can be calibrated by cores to specific processes, and thus that multibeam backscatter is a robust tool for constraining geologic processes active in a basin including present-day sediment distribution on the seafloor. Piston cores accurately placed on zones of potential hydrocarbon seepage interpreted based on multibeam backscatter can significantly impact exploration. Specifically, the presence of oil and gas in a basin, and the composition of the hydrocarbons, can dramatically reduce the exploration risk by providing information on source, migration, and maturity.

Introduction
Human beings have been gathering information about the seafloor since they first took to boats. Until the development of acoustic techniques, soundings were taken by lowering a weight to the seafloor (lead line), and marking the length. Acoustic techniques involving a " ping?? of energy sent out, and then received, by a transducer, only became commonplace after World War II (for an excellent discussion on the evolution of seafloor mapping, see Mayer, 2006). The next big leap in seafloor mapping capabilities came in the 1960s.
Seafloor Acoustic Backscatter Measurements With Multibeam Echosounders
Authors: De Moustier Christian 
Published: July 2010

Abstract
This paper is a tutorial on the fundamentals of seafloor acoustic backscatter measurements made with multibeam echosounders. Such measurements are used to infer seafloor geoacoustic properties, including: acoustic impedance contrast at the water/sediment interface, mean sediment grain size, spectral characteristics of the roughness of the water/sediment interface, contributions from subbottom layers or inhomogeneities in the sediment volume.

Introduction
From the 1960s to the mid-1990s, acoustic backscatter imaging of the seafloor was primarily done with towed sidescan sonar systems (e.g. Belderson et al., 1972; Mazel, 1985; Fish and Carr, 1990 & 2001), some of which had bathymetric capabilities (e.g. Blondel and Murton, 1997). Meanwhile, the hull-mounted multibeam echosounder technology has gradually improved since the early 1970s from a purely swath bathymetric survey function to include backscatter imagery (de Moustier, 1988; Lurton, 2002).
Today, most modern swath mapping sonar systems used in seafloor surveying collect swath bathymetry and concurrent seafloor acoustic backscatter data. When processed together, these data can be used for remote sensing of seafloor characteristics, with applications in geotechnical surveys (e.g. offshore drilling and mining, dredging and disposal, subsea cable and pipeline routes), in resource management (e.g. fisheries habitat assessment, coastal zone monitoring), in navigation and homeland security surveys (e.g. harbor entrances, waterways, Q routes), and in basic and applied research (e.g. sonar modeling, seafloor acoustic processes, mine warfare).
In this paper we shall focus on the particular application of multibeam swath mapping sonars to remote sensing of seafloor geoacoustic properties. The development is tutorial in nature and we begin with a short review of the relevant seafloor acoustic backscatter processes. Then, we consider how acoustic backscatter is measured with a multibeam echosounder, and what processing steps are required before inferences may be made about the underlying geoacoustic parameters. Finally, we review various inference and interpretation methods and conclude with cautionary notes on comparison of results from different sonar systems.

Seafloor acoustic backscatter processes
Seafloor remote sensing with multibeam echosounders relies on the acoustic backscatter processes that take place at and below the seafloor. These processes depend on the type and distribution of sediments in the survey area and on the corresponding geoacoustic parameters. Among these parameters, we focus on the acoustic impedance contrast at the interface, the roughness of the seafloor relative to the acoustic wavelength, attenuation and scattering within the sediment volume, and the angular dependence of the bottom backscatter process.
Efficiency And Economy Of Automating Displacements For FPSO Pipe Stress Analysis
Authors: Robleto Robert , Williams Jim 
Published: July 2010

Abstract
Because Floating Production, Storage, and Offloading (FPSO) modules experience significant deflections from wave motion as well as hog/ sag, on board piping must be analyzed to assure that it is suitably designed for high cycle fatigue. This is done by keeping accumulated damage to a value less than 1.0 using the Palmgren-Miner rule. In order to simplify the acceptance criteria, a method must be developed to convert allowable accumulated damage into an allowable stress range that pipe stress engineers are accustomed to evaluating. This is done by combining methods from PD5500, DVN publications and the Fatigue Handbook: Offshore Steel Structures Probabilistic Fracture Mechanics; Tapir 1985.
To consider the effects of deck bending and module sway, displacements must be calculated from the naval architects hull data for every restraint in the pipe stress analysis model. Multiple loading cases require this process to be repeated for each loading case being considered.
Most engineering companies have developed a technique for automating the computation of module and/or deck displacements. These values once computed must be entered into the pipe stress analysis software. This task normally requires 8 to 24 hours per calculation depending on size and complexity of the piping system being analyzed. Since the data has been manually entered it must also be checked, which requires another 4 to 12 hours.
If a method can be found to calculate displacements and then automatically load them into the pipe stress analysis software, significant cost savings can be realized through reduced engineering work hours. On a project requiring 100 calculations, the potential savings using a reduction of 25 hours per calculation will be 2500 hours. This will result in a cost savings of $225,000 using $90/ hour as the cost basis. Savings could range as high as $700,000 on large FPSO's. By using the Caesar II neutral file writer to import/ export input data, it is possible to automate this process. An engineer, after entering the piping geometry into Caesar II and assigning restraints at the applicable nodes, can export a neutral file which can be read into displacement generating software (this is a company proprietary tool) where the displacements and rotations are applied to each restraint node. This enhanced neutral file can be re-imported into Caesar II ready for analysis complete with displacements and rotations. The most complex calculations can be processed in less than 30 minutes. By automating this process it may be possible to reduce FPSO pipe stress analysis time by as much as 40%.
Perdido Development: Subsea and Flowline Systems
Authors: Ju G.T. , Littell Howard Steven , Cook Terry B. , Dupre Mike H. , Clausing Katrina Montrose , Shumilak Edward E. , Schoppa Wade , Blizzard William Allen 
Published: July 2010

Abstract
Perdido is located in the Western Gulf of Mexico in 7,817 feet of water. It is being developed with cutting-edge subsea technologies to mitigate the project's key development challenges, which include extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate formation tendency.
This paper provides an overview of the Perdido Development subsea and flowline system and its associated flow assurance strategy. This paper also includes reviews of the design, fabrication, and installation of key subsea equipment such as twophase separators, subsea trees, manifolds, top-tensioned production risers, umbilicals, and flowlines. In particular, the two enabling subsea technologies, subsea boosting system and surface Blow-Out Preventer (BOP) for drilling and completing of subsea wells, are discussed.
Unique features of the Perdido subsea system include:All wells are subsea (wet trees operated by umbilicals) and consist of 22 local Direct Vertical Access (DVA) wells and 12 offset wells.The subsea DVA wells are drilled, completed, and intervened through a single high-pressure drilling/completion riser and a surface BOP with the host rig.All production will flow from manifolds into five subsea boosting systems where gas will flow naturally to the topside facility, while liquids will be pumped using electrical submersible pumps (ESPs).

Introduction
The Perdido Development, jointly developed by Shell, BP, and CVX, includes the Great White, Silvertip, and Tobago fields and is located in the Perdido Basin and Foldbelt, in the Alaminos Canyon Protraction Area. This area is located in the western Gulf of Mexico, 200 miles south of Freeport, only eight miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a Spar with full offshore processing capabilities and pipelines for export.
SS: Imapct of subsea processing Power distribution: Powering New Frontier Ultra-Deepwater: R&D, Innovation or Evolution?
Authors: Noel Cornelia , Dee Ronald , Vicic John Charles 
Published: July 2010

Abstract
The subsea portion of the oil industry began as small power consumers connected to a bulk power system provider (a topsides host). The growing demand for oil and gas worldwide coupled with the depletion of existing fields is driving production towards deepwater assets further away from the shore or a host facility. Such fields require ultra-reliable bulk long-distance power that will push AC power transmission/distribution (T&D) to its technical limit. The technology challenges that the oil industry will face in realizing economic power supplies for ultra-deepwater require focus in a number of strategic areas. Reconciling these challenges with the continued growth in energy demand (the advent of the Subsea Processing era) highlights the need for a diverse, industrywide approach. For example, some estimates put the power need for subsea -pumping, -compression, - separation and -processing systems to as much as +30 MW (full field development).
The aim of this paper is to review systems that can supply power to the New Frontier Ultra-Deepwater. The focus will be on the identification and evaluation of optimal system(s) for the generation and delivery of electrical power. In tandem with this is a comparison of the three (3) competing power system architectures: local micro-grid power; long-distance AC T&D; long-distance DC T&D (emergent solution). In making this comparison, we considered the key performance indicators (KPIs): cost, efficiency, reliability, potential for ancillary services, and technology readiness level (TRL). The paper concludes with recommendations for future investigations.

Introduction
Subsea pumping and processing technology enables the industry to exploit additional deepwater and/or long offset reserves and accelerate production. The technology include: oil pressure boosting, gas compression, seawater injection, water separation/re-injection, amongst others. Deployment of these technologies depends on a reliable electric power system. The fundamental problem with the supply to, and demand for, electricity is its storage. Once generated, electricity must be delivered and consumed immediately owing to technical difficulties with, and the prohibitively high cost of, storage. In this regard, electricity is perhaps a unique commodity in that the rate of its production must balance the rate with which it is consumed at all times by the end-load.
The power system value chain elements are as follows (see Figure 1): power siting; energy sources; power generation; power transmission; power distribution; end load. Ancillary power system elements include data acquisition/control, energy storage, combined heat and power (CHP), amongst others.
Plate Tectonic Reconstruction of Nova Scotia
Authors: Luheshi Matt , Nunn Keith , Roberts David , Wilson Hamish 
Published: July 2010

Abstract
The Offshore Energy Technical Research (OETR) Association has initiated an industry standard Play Fairway Analysis (PFA) program. This program is intended to serve a pivotal role in stimulating industry interest in exploration of Nova Scotia's offshore petroleum resources by providing explorers with critical information about prospectivity and resource potential to aid in decision making.
The Play Fairway Program was initiated in May 2009 with a workshop including leading academic thinkers from Canada, Morocco and Europe. The workshop concluded that one of the important issues that needed to be addressed, as part of the overall Play Fairway Program, was plate tectonic reconstruction.
The purpose of the Plate Tectonic Reconstruction Project is to provide an integrated 3D model of the crustal structure and evolution of the Nova Scotia continental margin, in space and time, from rifting to spreading. This model will underpin an understanding of early rift and post-rift depositional environments and provide a predictive model for salt deposition and the distribution of Triassic and Early Jurassic source and reservoir rocks. The project includes a number of elements such as acquisition of new refraction data offshore Nova Scotia, reprocessing of refraction data offshore Morocco, reprocessing of long offset multi-channel seismic offshore Nova Scotia, merging and integrated reprocessing of potential fields data, and integrated interpretation of all these data. The integrated interpretation of these data will enable a revised plate reconstruction to be produced, together with a model for the along strike variation of rifting styles, for the Nova Scotia margin.
The tectonic analysis leads to an interpretation that allows for the possibility of an Early Jurassic source rock system offshore Nova Scotia and provides a model for the distribution of such a source rock system. This, in turn, greatly enhances the potential for hydrocarbon prospectivity.
This project is a key part of an extensive integrated PFA for offshore Nova Scotia.
SS FA- Deliquification of an Offshore Oil Well - An Innovative Approach to Overcome Paraffin Plugging
Authors: O&apos;Brien Shawn Patrick , Kiihne Eric , Macias Jose M. , Vita Eric William , Gonzalez Joel A. 
Published: July 2010

Abstract
A deliquification technique has historically proven effective for land-based operations. The objective was to deliquify a deepwater dry-tree oil well with minimal impact to normal offshore operational objectives. The deployment of a production chemical to successfully deliquify the oil well involved the study of typical well deliquification techniques for land based operations which were modified to address deepwater, offshore operations regulatory requirements and system objectives. This application also involved flow restrictions due to paraffin depositions in the tubing.
Typical liquid unloading techniques require system analysis, fluid modeling, deployment planning, and implementation. These techniques were applied to the offshore environment with special attention to deployment and implementation phases due to fluid flow-rate limitations associated with offshore production equipment. Modeling tools were used to identify required velocities to successfully unload the liquid hold up and to better understand expected performance.
This paper will discuss the project planning and processes used to successfully deliquify a flow-restricted liquidloaded deepwater oil well. Modeling data, critical flow-rate limitations of the system, and deliquification process planning are included. Results of this application will be discussed in further detail to help understand requirements of offshore chemicals induced deliquification techniques and lessons learned.
The use of a Flow Improver to remediate liquid loading associated with depleting wells offers another solution to offshore facilities. The modeling and identification of wells near the liquid loaded critical rate can prevent well downtime associated with pressure buildup and coil tubing techniques typically applied. This approach can significantly reduce CAPEX costs associated with artificial lift techniques while maintaining offshore operational objectives in regards to pipeline oil quality and water discharge regulatory requirements.

Introduction

Deliquification Techniques
Deliquification techniques have historically proven effective for land-based operations. Many different techniques have been used in the past. The majority of these techniques involve increasing the gas velocity or lifting the water to reduce liquid loading. Some of the different techniques for reducing liquid loading can be found in Table 1.
The Effects of Large Scale Forgings and Heat Treatment on the Mechanical Performance of Mooring Connectors
Authors: Hughes Paul , Flores William 
Published: July 2010

Abstract
A shackle failure in the Far East in 2007, called into question the integrity of some processes used in the manufacture of longterm mooring systems. This paper reports the results, so far, from a joint First Subsea Ltd and University of Sheffield's Institute for Microstructural and Mechanical Process Engineering (IMMPETUS) research into larger scale metal forging processes and the resulting mechanical properties.
The objective of the Large Scale Forging research project is to more fully understand what happens during the forging process and, in so doing, better characterise the micro structure of forged metals, its relation to Charpy toughness values (CVN), fracture toughness values and the design and integrity of mooring connectors.
Large scale metal forging is a complex, and far less understood process, compared with many other metals treatment techniques. Mooring components need to exhibit high levels of strength and toughness, as well as outstanding fatigue behaviour over an extended period. While the latter relies heavily on established computer modelling techniques, the factors governing strength and toughness are less well understood. The paper reports on the different aspects of the forging process including: chemical composition of the steel material, heat treatment processes, quenching and cooling rates and test procedures. In particular it will focus on the role and importance of heat treatment, cooling rate and geometry of the material on the mechanical performance of the finished forged connector.
Forging trials have been extensively carried out, comparing parameters like soak and quench times as well as cooling rates and durations. The results of the forging trials, so far, has been a better understanding of the optimum conditions for metals forging with respect to chemical composition and the relevance of microstructure due to internal thermo-couples and thermal imaging cameras. In addition, improved testing methodologies have been reviewed together with the development of a heat transfer model used to predict toughness properties along the ingot.

Introduction
Forged metals are widely used for chains, shackles and other mooring line accessories in offshore mooring systems. The failure of a mooring shackle in 2007 called into question the integrity of some processes used in the manufacture of long-term mooring systems. Moreover it highlighted significant gaps in the knowledge of manufacturing large scale forged items and the influence on their mechanical properties.
First Subsea Ltd, The University of Sheffield and Somers Forge Ltd have undertaken a project to identify best practice for the specification and manufacture of large scale forging and heat treatment for its subsea mooring connectors. The project is also intended to have wider implications for other forged metal mooring components such as chains and shackles.