bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring of Floating Offshore Installations' Wave Frequency Motions
Authors: Liagre Pierre , Gupta Himanshu , Banon Hugh 
Published: October 2008

Abstract
Severe hurricane activity of 2004 and 2005 has reminded the industry of the importance of integrity management of floating structures. One of the main methods used in assessing the fitness of a floating system after a hurricane event, is to evaluate the actual behavior of the hull, mooring and riser systems versus design assumptions using high and low frequency motions of the platform. As a result, vessels are typically outfitted with inertial six degree-of-freedom inertial navigation systems (INS) and differential global positioning systems (DGPS). Common practice is to use INS for wave frequency measurements whereas DGPS is used for low frequency drift motions.
Combining INS and DGPS signals into a single signal covering the entire frequency range requires the choice of appropriate cut-off frequencies for both instruments and the use of advanced filtering techniques. Both tasks are usually source of much debate.
The objective of this study is to demonstrate that modern DGPS have the same ability as INS to measure floating systems wave frequency motions and provide a redundant set of measurements that users can use to verify the accuracy of the INS data.
Using marine data collected on BP Holstein truss spar during hurricane Katrina and BP Atlantis semi-submersible during a 2006 winter storm, the wave frequency motions extracted from the DGPS signals after correcting for pitch and roll motions show very good agreement with the INS signals in the time domain.
Since both vessels are outfitted with DGPS of varying accuracy, the accuracy of these different systems is discussed. The results are also presented as a function of the sea states to demonstrate the ability of DGPS in the smaller sea states. The results of the study show that the DGPS can be used in the wave frequency motion ranges, which is typically been measured with INS. The results presented in this paper help in better understanding and interpretation of the field data and lead to better practices in the integrity management of offshore platforms.

Introduction
BP's fleet of deepwater floating offshore installations (FOIs) in the Gulf of Mexico include a tension leg platform (Marlin), three truss spars (Horn Mountain, Mad Dog and Holstein) and three semi-submersibles (Na Kika, Thunder Horse and Atlantis) moored in water depths ranging from 3,250 to 7,070 feet.
In the last five years, BP has led a significant effort to preserve and analyze the data collected by comprehensive marine monitoring systems installed on each of these FOIs. Even though the six degree of freedom motions of these three types of floating systems have been studied extensively during model tests and numerical simulations, a lot of interest is placed on capturing their true motions for several reasons:Comparison to predictions of fully coupled numerical models.Calculation of actual fatigue accumulation in the risers (H.H. Cook, 2006)Post hurricane investigation.
Use of Analytical Models and Monte-Carlo Simulation for Quantification of Uncertainties Associated With Gas Production From Hydrate-Capped Gas Reservoirs
Authors: Gerami Shahab , Pooladi-Darvish Mehran 
Published: October 2008

Abstract
A large number of studies are underway to evaluate the possible role of gas hydrates as a potential energy resource. While one class of such studies involves characterization and quantification of hydrates in geological setting suitable for exploitation, another class of studies involves development and use of mathematical models to estimate hydrate recovery under different operating conditions. Quantification of the hydrate resource using geological and geophysical techniques, while continuously improving is subject to very large uncertainties. A meaningful development plan should incorporate the associated uncertainty, requiring large number of simulation runs. This is impractical using currently available models, as (i) most of the available numerical models are not commercially available and (ii) setting up and running of these complex models is quite time-consuming. Furthermore, the accuracy associated with these models is not necessary, because the input parameters could vary over a wide range. Recently, the authors have developed an analytical model for prediction of gas production from hydrate capped gas reservoir. In this paper we present of this model and then use it along with Monte Carlo simulation to capture the effect of uncertainty in hydrate and reservoir parameters on the performance of the hydrate capped reservoir. The usefulness of these analytical models for fast engineering calculations, particularly those that are conducted at the beginning of the life of reservoirs (and are based on very limited information that do not warrant numerical simulation) is shown using a hypothetical case studies.

Introduction
The demand for energy has stimulated the development of the unconventional gas resources (such as gas hydrates) which are occur in enormous quantities around the world. Gas hydrates tend to form in two geologic settings:on land in permafrost regions, andin the ocean sediments of continental margins.
During the last decade a number of projects have been conducted for detection and characterization of the hydrate-bearing formations, drilling, logging, coring, production testing and mathematical modeling of hydrate reservoirs, with the eventual objective of assessing commercial producibility of gas from hydrate resources.
One type of hydrate reservoirs that are thought to be most amenable to production are those that overly free-gas bearing sands (i.e. hydrate-capped gas reservoir). Makogon9 reports that in the Messoyakha reservoir, where part of the reservoir lies below the base of the hydrate stability zone (and contains free gas), production of the lower conventional free gas led to the decomposition of the overlying hydrates by depressurization. Another example is the Eileen accumulation in Alaska25, where production testing using the depressurization method is underway.
Borehole Pressure Coring and Laboratory Pressure Core Analysis for Gas Hydrate Investigations
Authors: Humphrey Gary D. 
Published: October 2008

Abstract
Marine gas hydrate investigations, whether they be conducted as resource evaluations for national governments, as geohazard assessments for major oil companies, or as climate-related scientific endeavors funded through international funding agencies, have begun to develop common strategies. Gas hydrate can occur up to several hundred meters below the sediment-water interface, depending on the water depth and thermal gradients; consequently, for a full assessment of gas hydrate occurrence, nature, distribution, and concentration, samples must be obtained through drilling and coring. Samples retrieved and analyzed at full in-situ pressures using pressure coring techniques are the only way to ground truth the findings from other techniques, including physical and chemical analysis of non-pressure cores or the interpretation of seismic and borehole log data.
Thermal imaging of non-pressure cores provides an immediate and valuable method for observing the endothermic behavior of dissociating gas hydrate but does little in itself to characterize the gas hydrate morphology or concentration. Porewater analysis techniques rely on the freshening of porewaters when gas hydrate dissociates, generally measured via chlorinity; these analyses provide excellent spot measurements of the concentration of gas hydrate if the background chlorinity profile is well established, but tells the investigator little about the nature of the gas hydrate. Furthermore, in lakes or nearshore environments where the porewaters may have very low or highly variable chlorinities, this technique will be far less reliable or accurate. Only methane mass balance calculations from depressurization of cores recovered at full pressure provides the benchmark or " gold standard?? for gas hydrate concentration assessment.
Measurements of the density and volume of pressure cores through X-ray imaging and gamma densitometry have removed errors in estimation of pore volume, making this methane mass balance technique accurate and robust. Non-destructive testing and analysis of gas-hydrate-bearing cores at in-situ pressures and temperatures also provides detailed information on the in-situ nature and morphology of gas hydrate in sediments. The detailed profiles of density and VP, together with spot measurements of Vs, electrical resistivity, and hardness, provide background data essential for modeling the behavior of the formation on a larger scale. X-ray images show the hydrate morphology in relation to the sediment, which will control the kinetics of methane release. Gas-hydrate-bearing pressure cores subjected to X-ray tomographic reconstruction provide compelling evidence that gas hydrate morphology in many natural sedimentary environments is particularly complex and impossible to replicate in the laboratory.
ISO Floating and Fixed Standards ISO 19902, ISO 19903 and ISO 19904
Authors: Galbraith David Ninian , Wolfram Bob , Leivestad Steinar 
Published: October 2008

Abstract
The ISO 19900 series of international standards comprises different levels of standards, ISO 19900 giving General Requirements for offshore structures, ISO 19901 giving Specific Requirements for various aspects of offshore structures that have relevance to different types of offshore structure (in several parts), and then a series of standards giving requirements for the different generic types of offshore structure.
Of this last category, three have now been published; ISO 19902 for Fixed Steel Offshore Structures, ISO 19903 for Fixed Concrete Offshore Structures, and ISO 19904-1 for Floating Offshore Structures. The development of these three International Standards is described in this paper, which gives details of the scope, provenance, key features, contents, and organization of each of the three standards.
ISO 19902 is a development of API RP2A LRFD, but in the preparation of the International Standard a number of research and Development Joint Industry Projects (JIPs) were commissioned, and the enhanced knowledge from these projects, together with knowledge and experience from the offshore operating areas around the world, have been incorporated.
ISO 19903 is a new and somewhat different standard, as it deals with the entire task of engineering a concrete offshore platform facility, with mechanical systems, etc., rather than just the detailed design of its concrete members. To a large extent the standard relies on the existence of national or regional standards for design of concrete structures that can be safely used in an offshore concrete structure, as such structures can range from quite simple to really sophisticated structures.
ISO 19904-1 is a new standard entirely. It is based partly on API RP 2FPS, which was developed in the same timeframe, but includes concepts taken and harmonized from North Sea practice represented by then HSE and NPD guidelines and from class rules. Some text was written specifically for this standard, particularly the clause on structural integrity monitoring and various sub clauses elsewhere that represent lessons learned in from industry experience during the period in which the standard was written.
Greater Plutonio:BP's First Operated Project in Angola
Authors: Brown Sally A. 
Published: October 2008

Abstract
Greater Plutonio is BP's first operated project in Angola and enables BP to establish a prominent footprint in country. It also provides the base to build future developments as well as creating a local energy company which will deliver sustainable long term benefit to Angola. Greater Plutonio is located in Block 18 which covers 4,880 km2 approximately 150 km from the Angolan coast. The plan calls for the development of 5 fields - Plutonio, Cobolto, Paladio, Cromio and Galio. The development concept is for a large scale FPSO capable of processing 240,000 mbd, with a storage capacity of 2 million barrels. The FPSO being linked to 43 subsea wells at water depths between 1200 - 1500m via a complex riser tower system and an extensive subsea architecture of flowlines, umbilicals, manifolds, jumpers and trees. This paper summarises the challenges, successes, learning's and their application for future developments. It is supplemented by companion papers covering specific areas of the development from sand face to facilities (OTC - 19673, 19674, 19675, 19676 and 19669).
Subsea, Umbilicals, Risers and Flowlines (SURF): Performance Management of Large Contracts in an Overheated Market; Risk Management and Learnings
Authors: Oldfield Gerald 
Published: October 2008

Abstract
Greater Plutonio is BP's biggest subsea project worldwide and consists of 5 separate fields in 1500m of water, over an areal extent of 4,880km2, 150khm offshore Angola in Block 18. One of the many challenges of the development concept was to deliver the complex Subsea production system, Umbilicals, Risers and Flowlines (SURF) which will connect the 43 subsea wells to the spread moored 2 million barrel storage, new build FPSO with production capacity totaling 240,000 barrels per day, in an integrated manner over a fast track schedule to allow a safe, efficient and phased start up, with rapid production ramp up. The challenge was heightened by a commitment to deliver the highest level of local Angolan content ever achieved to date.
This paper will address the challenges in project managing SURF projects of this size and highlight some of the unique aspects and challenges of this development, particularly given its Angolan content and market conditions by applying risk management principles and applying learning from previous deepwater projects in WAF, GoM and West of Shetland It is supplemented by companion papers covering specific areas of the development from sand face to facilities (OTC - 19673, 19674, 19675, 19676 and 19669).
The key points and challenges to note about the SURF system are:43 wells with flexibility and expandability in the subsea architecture for up to 88 wellsSingle compliant riser tower with condition monitoring system, fabricated and assembled in AngolaHighly dynamic seabed flowlines subject to high lateral buckling forces and end expansions107km dynamic and static production control, chemical injection and data acquisition umbilicals150km production insulated flowlines, water injection plastic lined, gas injection and service flowlinesSimultaneous subsea construction, commissioning, start up, production and offtake operationsProvision for a future subsea gas export offtake
The project was led by a core BP Project Leadership Team supported with directly hired contract staff co-located to major contractors' offices to work in integrated teams, through FEED, system engineering, detailed design, procurement, manufacture, fabrication, installation, commissioning, start up and production. Throughout the project functional departments provided expert technical support and integrity assurance with formal reviews and specialist advice.
BP partnered with their key contractors to identify key project drivers, issues and challenges, and then mapped out a plan to systematically improve safety performance, especially in Angolan fabrication yards and for offshore simultaneous marine construction and commissioning operations.
This partnering approach increased ownership and ensured that improvements were embedded in the contractor's systems and procedures, as well as enabling the contractors to take advantage of the significant safety resources/experience available within BP.
Emerging Geophysical Technologies: Downhole Microseismic Reservoir Monitoring (MRM): A New Instrumentation Technology for Monitoring the Digital Oilfield
Authors: Wilson Stephen , Le Floch Gilles , Jones Rob 
Published: October 2008

Abstract
As a seismic technology, the microseismic technique is unique in that it provides direct 4D information about the stress changes in the reservoir that are caused by injection and production operations. These changes in stress are common to all producing reservoirs. As a consequence reservoirs emit packets of seismic energy and information about all the small slip events triggered by oilfield operations.
It is possible to detect tiny slip magnitudes corresponding to only a few microns of movement. Such movements may correspond to slip on a fracture, movement within the cement, slip on bedding, the opening of a frac or even precursory slip in the completion. Mapping these changes in both space and time provides a unique insight into stress change in the reservoir, the overburden and the well stock. Although this activity is triggered by oilfield activity, the emitted energy derives from strain energy stored within the rock mass.
Offshore wireline deployments have shown the value of the microseismic technique and more recent onshore pilots have emphasized the value of permanent sensor installation for reservoir management (Jones et al., 2004).
Until very recently microseismic monitoring has been constrained by the requirement to deploy seismic sensors within inactive monitor wells. The recent availability of seismic technology that can be deployed in live wells represents a step-change in our ability to seismically monitor hydrocarbon reservoirs. Such monitoring can now take place even during active injection or production and in offshore environments where monitor wells are rarely available.
The key stakeholders in terms of deploying and utilizing the value of this technology include asset managers, engineers involved in production, drilling and reservoir management, together with the seismologists who process the data and deliver value to the reservoir engineer.
Microseismic reservoir monitoring represents a new deep-reading technology to understand reservoir processes and thereby better optimize reservoir management and better target field development investment with the goal of producing more oil at a reduced cost. The installation of appropriately designed systems also offers the prospect of combining microseismic monitoring with conventional downhole reflection seismic technology in the form of VSP on demand (Wilson et al., 2004).
Improved EPC Integration Management for FPSOs
Authors: Kim Jung-Goon 
Published: October 2008

Abstract
The paper presents a ship-builder focus on integration management in EPC contracts that combines the requirements of client (owner), subcontractor and vendor, minimizes cost and schedule delays and utilizes international standards in product delivery. The interface issues have been traditionally identified as the challenges and risks in the construction process. SHI presents the refinement of construction management method based on Nexus-1 FPSO as it applies lessons learned in subsequent projects.
The methods employed in integration management and its' elements are presented. They include alignment with international project management practices (PMI), presence of dedicated integration (interface) manager for full project lifecycle, use of a common interface procedure and interface register and protocols, integration workshops and ongoing integration assessment, utilization of formal processes that enhance communication and understanding in multi-national projects, focus on communication with vendors and subcontractors, continuous monitoring and control for optimization, focus on efficiency of hull / topsides interface to name just a few.
Effective management integration methods ensure reduced risk, savings in time and cost, and provide efficient design that minimizes interface problems between all involved parties.

Contents
1.0 Introduction 2.0 The Generic FPSO Concept & Specification 2.1 Dimension and Characteristics 2.2 Process Description 2.3 Major Design Parameter (Topside) 2.4 Module Description 2.5 Safety and Environmental Considerations 2.6 Future Design 3.0 Classification, Rules and Regulations 3.1 Flag States 3.2 Classification 4.0 Scope of Works 5.0 EPC Projects Integration Management 6.0 Project Phases and EPC Execution Principles 7.0 Interface Management 8.0 Project Execution 8.1 Overall Schedule 8.2 Detail Engineering Phase Challenges 8.3 Major Issues for Regulatory and Safety Requirements 9.0 Conclusion
High Integrity Pressure Protection Systems (HIPPS) Development for the Gulf of Mexico: Update on Deepstar, API 17O and Industry Developments
Authors: Lindsey-Curran Christopher J. 
Published: October 2008

Abstract
As oil and gas exploration has moved into increasingly deep water in the Gulf of Mexico, the potential to find increasingly higher pressure and higher temperature reservoirs has increased. High Integrity Pressure Protection Systems (HIPPS) are seen as essential for development of these prospects. The paper will cover the key differences between applying HIPPS in the Gulf of Mexico compared to North Sea applications, as well as the associated regulatory process involving the Minerals Management Service, the regulatory authority in the Gulf of Mexico. It will also provide an update on API 17O and industry developments.

1.0 Introduction
The installation of High Integrity Pressure Protection Systems (HIPPS) has been limited to the North Sea for subsea applications. As exploration and drilling have moved into deeper water in the Gulf of Mexico, discoveries have increased in pressure and also temperature resulting in an increased need to address the application of HIPPS technology in this region. Although there are a number of subsea systems operating successfully in the North Sea, it has not been possible to transfer this experience directly to the Gulf of Mexico without a significant amount of ground work. This paper discusses the key differences, the impact on subsea architecture and the work with the regulatory authority associated with HIPPS technology.
Developments in Underwater Technology and the Role of the Learned Society
Authors: Gallett Ian Niacholas Leigh 
Published: October 2008

Abstract
This paper reviews the whole round of technology used underwater and looks to the future direction each of the technologies is going. It also seeks to bring out areas where these technologies can cross-fertilize and where diversification of the skill sets developed can be used elsewhere. Examples are the use of experience gained in the oil & gas sector being used in the offshore renewables area and the retro-fitting of technologies developed for autonomous underwater vehicles into ROVs. The paper concludes with a review of how a learned society, such as the SUT, can contribute to the development of subsea technology and its global and sectoral diversification.

Introduction - Underwater Technology
There are many uses of technology subsea. The main purpose of this presentation is to highlight these and to indicate developments in these which are important to the future efficient and cost effective extraction of resources to be found underwater. These are mainly described in the oil & gas sector, but it is also emphasised where the technologies and skill sets developed in this sector can be utilised elsewhere and where developments are taking place in nascent sectors which have a strong relationship with oil & gas. The role of a learned society, such as the Society for Underwater Technology (SUT) is important in disseminating knowledge vertically within a sector, but is also vital in the transfer of knowledge across the perceived boundaries between sectors.
For convenience, this presentation is broken up into six operational areas of interest and two ones that can be described as enabling technologies. The latter two find applications across many if not all of the operational ones. The six operational areas are:Subsea Engineering & OperationsMarine Renewable EnergiesOcean ResourcesOffshore Site Investigation & GeotechnicsEnvironmental ForcesUnderwater Science
The two enabling technologies are:Diving and Manned Submersibles (ie man underwater)Underwater Robotics (ie machine underwater)
Each will be dealt with in turn.