bluuebunny/crossref_metadata_2025_split huggingface dataset:
Caspian Challenge for Marine Installation
Authors: Wilson Frank , Munro-Kidd Alex 
Published: October 2008

Abstract
The geographical position of the landlocked Caspian Sea presented a huge challenge for the marine installation of the ACG (Azeri, Chirag, Gunashli) development offshore Azerbaijan. Access to the Caspian is limited to two canals in the north which are frozen for up to six months of the year. There was limited reliable hydrographic and meteorological data and the Caspian had a history of relaxed marine discipline.
The ACG Project had a pipe lay barge, heavy lift derrick barge, transportation barge and dive support vessel available for installation activities, all requiring major upgrades prior to utilization. The Project brought in a new supply vessel that was converted into a dedicated subsea construction vessel.
This paper describes the technical challenges, schedule constraints/optimisation and innovative installation solutions from project start through to offshore installation.
The marine installation was successful regardless of the limitations of the vessels and equipment available. Installation included;4 Drilling Templates with 12 well slots (circa 120 te each)Six Jacket Structures (circa 16000te) in water depths from 118m to 175m.Six Floatover Topside Facilities with an installed weight of up to 15800te.4 Brownfield Packages (water coalesor and injection equipment)1200km of Pipelines from 4 to 30 inch diameter.3 Subsea Remote Water Injection Manifolds10 Subsea Remote Water Injection Trees400km of Fibre Optic Cable for telecommunications, IT and integrated control systems.2 Power Cable systems 5.6km and 9.6km in length to provide interfield power.6 Wye Structures (circa 120te each)
Numerous vessel upgrades were necessary to optimise the efficiency of the vessels available to the project. These were strategically planned to minimise impact on achieving key milestones. For the subsea system, facilities to receive, test and store were established.
The contracting strategy with the main contractors proved successful in achieving project delivery targets. Major interfaces were managed with other delivery teams, Company Operations and third party assets.
The ACG Project delivered a number of marine ‘firsts’ in the Caspian, including the floatover of 15800te topsides, wet towing of 600te jacket piles, pre-drilling templates, pin pile temporary jacket foundations and use of underwater hammers. This was achieved through creative design and installation execution strategy, integrated planning across many stakeholders and by significantly enhancing the existing marine fleet with the optimisation of vessel upgrades.
An Overview of the Roncador Field Development, a Case in Petrobras Deep Water Production
Authors: Barbosa Vilmar Carneiro , Dias Ronaldo 
Published: October 2008

Abstract
The giant field of Roncador was by far the largest discovery made in Brazil in the 90's. Holding more than 3.3 billion boe in reserves and located in ultradeep waters - 1,500 to 1,900 meters - its development has set up new technological and economical frontiers for Petrobras's offshore production.
Located in the northeastern portion of the Campos Basin, 125 km off the Brazilian coast (Figure 1), Roncador covers an area of approximately 110 square kilometers and is comprised of two main blocks, saturated with 18 to 31° API oil.
Due to the differences in oil characteristics and to the massive reserves involved, PETROBRAS decided to develop Roncador in modules. This paper describes the track record since the discovery and presents the situation of the field a few months after two new floating units started production: semi-submersible P-52 and FPSO P-54. Petrobras main plans for two other modules in the coming future are also outlined.

Roncador History
Roncador was discovered in 1996, when Petrobras drilled the wildcat well 1-RJS-436A, in 1,853 meters of water, and found an accumulation with light oil (28 to 31o API) in the area which is known today as Module 1A (Figure 2) located in the eastern and deepest part of the field.
Based on the success of its portfolio of offshore projects in Brazil and the good results of PROCAP 2000, its technological capability program to produce oil and gas in ultradeep waters, Petrobras made the decision to develop Roncador with parallel activities, rather than in a more traditional sequential strategy. The company began, simultaneously, to:Drill appraisal wells;Design an Early Production System (EPS) - in order to anticipate revenues and gather reservoir data for the next phases;Design a long-term production system for the northeastern area of the field - flexible enough to accommodate the surprises that would certainly come up along the way;Develop equipment suitable for 2,000 meters of water.
Due to a period of scarcity of deepwater rigs, the appraisal wells were only drilled in 1998. They showed there were different conditions in other areas of the field, which contained crudes with densities varying from 18 to 22o API, and presented a CO2 content of up to 4.5%. Through the years the different areas received several denominations, until a permanent nomenclature was established, as can be seen in Figure 2.
Kuwait Oil Company Employs a Systematic Approach to Ensure Successful Underbalanced Drilling Project: A Case Study
Authors: Kabir Mir Md. Rezaul , Qutob Hani H. , El Saloussy Essam K. , Boutalbi Said Mohamed , Ambastha Anil Kumar , Al Sabea Salem Hamad , Villatoro Jaime J. 
Published: October 2008

Abstract
Kuwait Oil Company (KOC) is considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their oil and gas fields. Among the various options available to achieve these objectives, Under-balanced Drilling (UBD) technology is considered to be one of the most effective methods when it is effectively applied in conjunction with horizontal and/or Multi-lateral well drilling and completion techniques Accordingly, KOC decided to pioneer the introduction of this new technology by employing a systematic scientific approach to screen the Mauddud reservoir in the Greater Burgan field for under-balanced drilling candidacy, in order to ensure a successful implementation of the pilot project.
The screening process incorporated reservoir, production, drilling, Geology & Geophysics and operational data with risk analysis incorporated into a rigorous expert system aimed at maximizing the value of any UBD operation. The screening process was performed in two phases; a high level low resolution screening and in depth high resolution analysis.
Phase I comprised of:Evaluating and ranking the Mauddud reservoir with respect to its risked probability of being successfully exploited with horizontal underbalanced drilling and completion techniques as opposed to conventional methods.Comparing candidate reservoirs against global database of analogues proven to be suitable with UBD.
Phase II comprised of:Quantifying drilling-induced damage and determining the impact on the productivity on the Mauddud reservoir.Comparing under-balanced and overbalanced costs, production rates, projected revenues and Net Present Value (NPV).
This paper describes the expert system methodology used in the screening process and provides a discussion of the results obtained.
The Phase II study findings provided KOC with detailed damage analysis, production forecast and economic benefits that under-balanced drilling could offer as compared to conventional drilling & completion technologies.

The UBD Screening Process
This paper investigates the reservoir suitability of underbalanced drilling using an Expert System screening process that was developed in conjunction with leading industry consultants to increase success in candidate selection and to evaluate the benefits of underbalanced drilling over traditional drilling and completion technology in terms of reservoir performance.
The screening process began by taking basic information for the Mauddud reservoir and processing the information through the expert system phase I software. This software rates the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced compared to overbalanced drilling and completion techniques. All data input was reviewed for completeness and consistency.
Deepwater Mooring With High Stiffness Polyester and PEN Fiber Ropes
Authors: Davies Peter , LeChat Celine , Bunsell Anthony , Piant Anne , Francois Michel , Grosjean Francois , Baron Patrice , Salomon Karine , Bideaud Charles , Labbe Jean-Pierre , Moysan Anne-Gaelle 
Published: October 2008

Abstract
The benefits of synthetic fiber ropes for deepwater station keeping are now well established and their use is expanding. Nearly all current applications use a single grade of polyester fiber, but for different supports and environments this may not be the optimal choice. Properties of polyester fibers can be modified by adjusting processing parameters and there are other fibers available such as PEN, which offer higher stiffness. This study examines the benefits of intermediate stiffness fibres, stiffer than standard polyester but less stiff than the high performance fibers. The results indicate that there is scope for improving mooring line performance and reducing line weight by careful evaluation of material options.

Introduction
Polyester fiber ropes are finding increasing applications in offshore mooring systems as production moves to deeper water. Following successful installations offshore Brazil in the late 1990's [Pellegrin 1999] the first Gulf of Mexico mooring was for the Mad Dog spar [Bugg 2004] in 2004, which employed 1200 tons of polyester down to 1670 meters water depth. The recently installed Independence Hub platform also used polyester moorings, in 2440 meters water depth [Paganie 2007]. Different rope constructions have been used but these mooring lines were all composed of similar high tenacity polyester fibers. The Red Hawk spar [Haslum 2005], also installed in 2004, used a modified polyester fiber with a higher initial stiffness to facilitate installation, and this raised the question of whether a higher fiber stiffness might be beneficial for other supports and allow rope diameter to be reduced. Previous work within the French Mooring line project [Davies et al 2002] studied high performance fibres such as aramids and HMPE and concluded that their very high stiffness, while allowing much smaller rope diameter and weight, did not improve durability as it would result in high fatigue loading of the metallic components of the mooring line. However, there is an intermediate stiffness region, shown in Figure 1, situated between the currently used fibres, with initial tensile modulus around 10-15 GPa, and the high performance fibers (&gt; 60 GPa) which has not been explored previously for deepwater mooring applications.
Modeling Overburden Stress Change Due to Compaction of Stacked Reservoirs, and Application of Model Results in 4D-seismic and Infill Drilling
Authors: Hindriks Kees O.H. , Schutjens Peter Maarten , van der Horst Juun , Collins Charles Louis 
Published: October 2008

Abstract
A compacting reservoir remains physically connected to the rock surrounding it. Therefore, as the reservoir deforms and compacts, stresses will change and reorient themselves in the reservoir as well as in the overburden, underburden and sideburden, and there will be deformation in these rocks too. It is a well known and extensively described physiological phenomenon that stresses and strains induce changes in seismic velocity. Thus, reservoir deformation induces changes in velocity affecting the seismic wave throughout the basin. For certain combinations of velocity change and overburden thickness, vertical integration of the local traveltime changes may lead to timeshifts of several milliseconds, which can be measured in well-repeated seismic surveys. Timeshift technology has an interesting application in reservoir monitoring: Maps of timeshifts could indicate the areal distribution of reservoir compaction and thus reveal the areal distribution of depletion. Timeshift analysis then has the potential to help determine compartmentalization, locate bypassed oil in undrained compartments, identify new drilling targets and sidetracks, avoid expensive infill wells, and eventually decide when to abandon a field. Promising patterns of timeshifts of up to 15 milliseconds have already been observed in several fields.
We simulated the geomechanical effects of the depletion of stacked oil-saturated reservoir sands. The calculated deformation and stress changes were used to calculate timeshifts as a function of production. Reasonable agreement was obtained between calculated and measured timeshifts. However, the fact that the measured timeshifts resulted from stress perturbation due to the combined effect of several stacked reservoirs complicates their interpretation: It requires a good (i.e. field-data-proven) static and dynamic model for all sands to correctly model their effect on the overall timeshift signal. Only then can the remaining difference between synthetic and field-observed timeshifts be used to monitor and interpret the production performance of a target "problem reservoir" within the stacked pay. Our models also suggest that stress changes in rocks overlying compacting reservoirs are complex and anisotropic, and dependent on proximity and structure of the relatively stiff formations. When these are present, the 3D-variation in stress state, and not the 1D-variation, should be used to compute and analyse timeshifts in 4D-seismic data.
Marine Support to Offshore LNG Terminals
Authors: Gourmelon Jean-Yves 
Published: October 2008

Abstract
Export and import offshore LNG terminals have a bright future… and the technology is here.
As part of the most visible benefits are stranded gas monetization, no land availability issues, reduced administrative pressure, and distance from politically unstable regions.
The Floating LNG industry aims at operating anywhere with maximum uptime, while addressing those familiar and essential concerns: safety, security, environmental responsibility and cost.
Among the challenges presented: access to resources and markets are not always located in the most tranquil waters, and valuable gas reserves can be at a significant distance offshore.
Local regulations might still impose serious constraints. Lastly, LNG carrier maneuvers and cryogenic liquid cargo handling pose different problems while performed in unprotected waters.
Because its role is to assist, protect, supply, maintain, and build, Marine Support is critical to the success of this great adventure.
As it has been with the advances of offshore oil exploration, this industry is coming up with adapted means to serve the emerging Floating LNG activity.
The pioneer of offshore marine support to the oil and gas industry is actively supporting the development of optimized solutions. Its approach is a combination of early project involvement, procedure development, research participation, and innovative ship design.
This paper will develop the notion of " Terminal Integrated Marine Service?? applied to offshore LNG, and describe the " anatomy of a modern LNG Multipurpose Offshore Support Vessel??.

Introduction:
It is assumed in this paper that not everyone is familiar with the emerging offshore LNG industry, its general economic environment, and recent technologies.
The purpose here is to provide an overview on the subject in order to afford an understanding of the marine service context around offshore LNG, and better show the contribution of our industry to its development.
Discussed during years, the move to offshore LNG operations is now clearly underway. It is a " new?? industry with hesitations and complexities, determined to succeed and now evolving rapidly to a more mature stage.
On a marine support standpoint, this " newness?? appears as a mix of " dejà-vu?? and unprecedented challenges. In an offshore stormy environment, how can we safely berth/moor a $200 billion, relatively fragile vessel so it can offload its hazardous cargo?
This view might look extreme…but this is the challenge. Fortunately, we will see that safety requirements, experience, research and technology are here to assist.
Some technology is around the corner that will also bring us closer to the comfortable " dejà-vu?? situation.
AUV and ROV Data Integration to Identify Environmentally Sensitive Areas in Deep Water
Authors: Hewitt Antony T. , Smith Jason , Weiland Richard John 
Published: October 2008

Abstract
This paper describes a methodology for integrating Autonomous Underwater Vehicle (AUV) geophysical data with Remotely Operated Vehicle (ROV) video in order to predict environmentally sensitive deep-water chemosynthetic habitat. The methodology was developed using AUV geophysical data and ROV video acquired in BP's Puma appraisal area, in the U.S. Gulf of Mexico. The results from the AUV survey indicated dozens of hydrocarbon seepage sites with the potential to support high-density chemosynthetic communities. These communities are protected by U.S. environmental regulations and, thus, could significantly impact field development plans. The ROV video revealed a few high-density chemosynthetic communities and cleared certain critical areas for potential development, but it still left numerous possible hydrocarbon seepage sites un-cleared. It would have been a costly undertaking to inspect each site by ROV when they are so numerous and widely separated. Therefore, an alternative means of clearing as many of these sites as possible was needed.
Upon integration of the ROV video with the AUV data, the following important observations were made:Densely populated chemosynthetic communities in the Puma area only occur at hydrocarbon seepage sites with relatively large (several 10's of cm or larger) carbonate outcrops;there is a strong correlation between this carbonate substrate and high-intensity backscatter in AUV multibeam sonar data; and, carbonate outcrops are distinctly visible in the AUV sidescan sonar data as anomalous seafloor mounds.
These observations suggested that ROV observations could be used to calibrate the AUV geophysical data. The calibrated AUV data could then be used to predict what other sites away from the ROV survey track (without direct visual inspection) have the most potential for supporting high-density chemosynthetic communities.
Based on the calibration results, inferred hydrocarbon seepage sites that exceed a specific seafloor backscatter intensity level, and contain anomalous seafloor mounds interpreted as authigenic carbonate, are the areas with the most potential for supporting high-density chemosynthetic communities at Puma. Other inferred hydrocarbon seepage sites that do not meet these criteria have a low potential for supporting high-density chemosynthetic communities, and are less likely to be subject to environmental regulations. The methodology utilized here helped prioritize areas of environmental concern at Puma, incase additonal ROV investigation is required. Additionaly, this method may be applicable in other settings where suitable AUV data and sufficient " ground-truth?? from ROV video exist.
Estimation of Thermal Properties of Methane Hydrate Sediment
Authors: Yamamoto Yoshitaka , Ohtake Michca , Kawamura Taro , Tsuji Tomoya , Tsukada Yuichi 
Published: October 2008

Abstract
Thermal conductivity of real hydrate-layer sand grain, which was recovered from the sediment under sea bottom near Japan, was measured with hot-disc transient method. That of Toyoura standard sand was also measured for comparison. Thermal conductivity of natural methanehydrate-layer sand was 3.8 ~ 5.8 [W/mK] at measured condition (263K~283K, 0.1MPa). This value was lower than that of Toyoura standard sand (8.6 ~ 9.4 [W/mK]) at the same condition. Thermal conductivities of the natural hydrate-layer sand grain and artificial methane hydrate (MH) mixtures were also measured at the condition that imitated the real circumstances of sediment under sea bottom (278K, 10MPa, water saturated). The value was remarkably decreased with the increase of MH concentration at 0vol% ~40vol%. While, it was not so much changed at higher than 40vol%. Estimation of thermal conductivity of natural sand-MH-water three component mixtures was carried out. As a result, the series-parallel conjugation model with varying the contribution parameter reproduced measured values correctly. This is consistent with the idea that structure of measured sand-MH mixed samples should be changed around 40vol% of MH.

INTRODUCTION
Gas hydrate is a clathrate compound that is composed of guest gas molecules and host water cages1. Recently, it becomes well known that there are huge amount of methane hydrate in the sediment under sea floor as same as land areas of permafrost regions. Since this gas hydrate contains large quantity of methane gas, it is considered as one of the substantial future energy resources. Thus, the investigation to recover it from the sea bottom near Japan was launched. In this investigation, thermal properties such as thermal conductivity, heat of dissociation and heat capacity of gas hydrate sediment are very important to evaluate economy of gas hydrate recovery. However, there is not enough experimental data for those thermal properties. Especially, very few data is reported for thermal conductivity of methane hydrate with soil and water2, 3. In this paper, thermal conductivity of natural hydrate-layer sand grain was determined by comparing the measured apparent thermal conductivity of water-saturated samples and that of estimated values with mixing model. Thermal conductivities of the natural sand grain and artificial methane hydrate (MH) mixtures were measured at the condition that imitates the real circumstances of sediment under sea bottom. Estimation of thermal conductivity of natural sand-MH-water three component mixtures was also carried out.