bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modern Deepwater Site Investigation: Getting It Right the First Time
Authors: Campbell Kerry J. , Humphrey Gary D. , Little Robert L. 
Published: October 2008

Abstract
Deepwater site investigation for petroleum production facilities requires much more than the simple one-boring approach that has been common at many continental shelf sites. Instead, because foundation-zone soil and geologic conditions found at many deepwater sites can be complex, a multi-phased approach that integrates and analyzes various geoscience and geotechnical data is required to optimize deepwater siting, geohazard risk assessment, and foundation design. This paper summarizes best practices for planning and executing a modern deepwater site investigation. The paper is based on our experience in carrying out various aspects of more than 100 deepwater site investigations over some 20 years. Although others have documented case histories illustrating specific deepwater site investigations, described various data acquisition tools, and discussed geohazards risk assessment in some detail, to our knowledge no generic, public summary exists that:explains the numerous considerations and significance of each in planning and executing a deepwater site investigation;describes the range and significance of geoscience and geotechnical components that can be required;gives the generic phases and sequence of execution required to optimize the process; andprovides guidance on the cost and schedule time required to carry out a deepwater site investigation.
The paper outlines a methodology for efficient, effective deepwater site investigation that is a useful explanation and guide for anyone responsible for this activity. The methodology will help operators optimize the planning and execution of deepwater site investigations, including geohazard risk assessments, and deliver results to project design teams in a timely manner. Unlike major operators, most independent operators and facilities designers/ constructors do not have site investigation and geohazard specialists on staff who are experts in the methodology presented. This paper is written principally for these organizations and provides them with a practical methodology for planning and executing effective deepwater site investigations.

Introduction
Purpose and Scope. The purpose of this paper is to describe what we believe to be the best-practice approach to a modern deepwater site investigation required for various petroleum exploration and development activities. Specifically, the paper outlines a methodology for efficient, effective deepwater site investigation and is intended as a useful explanation and guide for anyone responsible for this activity. The paper briefly describes what needs to be done and the various tools used, why it is important to do the various tasks involved, and when and in what sequence they should be done. The paper generally does not describe how to do the individual tasks as many other previously published papers have discussed details of deepwater site investigations (see References and Other Selected Literature at end).
Permeability of Laboratory-Formed Hydrate-Bearing Sand
Authors: Kneafsey Timothy J. , Seol Yongkoo , Gupta Arvind , Tomutsa Liviu 
Published: October 2008

Abstract
Methane hydrate was formed in moist sand under a confining stress in a long, x-ray transparent pressure vessel. Three initial water saturations were used to form three different methane hydrate saturations. X-ray computed tomography (CT) was used to observe location-specific density changes caused by hydrate formation and flowing water. Gas permeability was measured in each test for the dry sand, moist sand, frozen sand, and hydrate-bearing sand, and results of these measurements are presented. Water was flowed through the hydrate-bearing sand, and the changes in water saturation were observed using CT scanning. Inverse modeling will be performed using these data to extend the relative permeability measurements.

1.0 Introduction
Gas hydrate-bearing deposits present in the permafrost and in suboceanic environments have been identified as potential sources of natural gas. The production of natural gas from hydrates will pose many challenges, among which is the economic viability of producing gas from a particular resource. This interest in gas hydrates has induced many laboratory studies focused on various aspects of gas hydrates in the natural environment.
Pristine samples of natural gas hydrates have been difficult to retrieve and make measurements on because the hydrates are not stable at atmospheric conditions and require cold temperatures or high gas pressures to stabilize them. Pressure coring has been successfully performed, retrieving the most representative samples so far, however, these are not readily available for all studies, or in some cases not amenable to the needed study.
Several techniques are used to make gas hydrates for laboratory study. In the ice-to-hydrate method (Stern et al., 1996), ice is contacted with methane at the appropriate pressure, and then melted resulting hydrate forming. The hydrate can then be pulverized and mixed with a mineral substrate and compacted. In the excess gas method (Handa and Stupin, 1992), water is distributed throughout a mineral substrate (ie. sand or silica gel) and the mixture is brought to hydrate-stable conditions causing hydrate to form. In the dissolved gas method (Tohidi et al., 2001), water containing sufficient dissolved guest molecules is brought to hydrate-stable conditions and hydrate forms.
Permeability (the resistance to fluid flow under a pressure gradient) and relative permeability (the effect of the presence of other phases such as gas hydrate that interfere with the flow of the fluid of interest) are among the most important parameters governing gas production from a hydrate-bearing reservoir. From the gas production perspective, a large gas hydrate reserve with low permeability can be less desirable than a smaller reserve with higher permeability. Understanding the effects of the presence of gas hydrate in the porespace on permeability and water and gas relative permeability is necessary to more accurately predict natural gas production and economic viability from hydrate-bearing reservoirs.
Improving Reliability and Reducing Intervention Costs of Ultradeep Subsea Technology at the Design Stage
Authors: Fanailoo Pedram , Andreassen Goran 
Published: October 2008

Abstract
The current trend in offshore exploration and production (E&P) is geared towards developments in greater depths and harsher environments. The challenge of realizing fields at depths of greater than 5,000 feet normally requires unproven technology operating in harsh environments.
Deferred production is a function of reliability and intervention times. Harsh operating conditions in deep waters will have a negative impact on reliability. Long mobilization times for intervention vessels and availability of spare parts are also drivers of the performance of subsea facilities. High day rates for intervention vessels operating in deep waters represent an additional risk to project economics.
Target levels of reliability and production availability can be ensured during early design phases through a systematic and rigid reliability management program. As part of the early design optimization effort, a comparison of alternative intervention philosophies and their impact on project economics should also be evaluated. Alternative subsea intervention philosophies may be on an:On demand basis - which is subject to the availability of resources and costs at the time.Contract basis - where intervention resources are available based on agreed contract agreements.
This paper describes the potential risks involved with the reliability of novel subsea solutions required for deep water production, the impact of capital intensive intervention costs and a risk-based approach that can be applied to optimize subsea reliability, design and intervention planning. Det Norske Veritas (DNV) has successfully applied detailed simulation modeling techniques within a risk based approach to optimize subsea developments. DNV has supported operators with the following:Estimates for the reliability of novel ultra deep subsea equipment.Prediction of produced and deferred production volumes.Criticality analysis.Concept evaluation.Evaluation of alternative intervention philosophies.Gains in Net Present Value (NPV) based on optimization of design, reliability and intervention planning.
Deepwater hydrocarbon production is expected to grow from 10% to 25% of total offshore production by 2015 as hydrocarbon deposits in shallow waters and in more accessible regions become depleted. More is being invested in subsea technology to face the increasing demand for systems and equipment to recover hydrocarbons in deep and ultra-deep waters (greater than 5,000 ft / 1,500 meters). This shift in industry focus will result in some key challenges in the decade ahead.
The overall through-life Net Present Value (NPV) of a subsea project is dependent on three factors:Capital Expenditure (CAPEX).Operational Expenditure (OPEX).Revenue Losses.
Lessons Learned on the Open Hole Completions for the Two HPHT Retrograde Gas Condensate Fields Using Expandable Liner Hangers, External Sleeve Inflatable Packer Collars and Swell Packers for Zonal Isolation
Authors: Kim Yong-Seok , Kwang Kwon Ou , Murugappan Basker Stargard , Williford James W. , Jackson Alan Tancel , Nizam Irwan , Lim Derek Chiong Huat 
Published: October 2008

Abstract
Valuable lessons have been learned from the development of eight retrograde gas-production wells located in offshore Vietnam operated by the Korean National Oil Company. The intent of this paper is to share these lessons by presenting the concepts considered for well design, the selection process for the completion equipment and techniques, the preplanning for the installations, and the experiences encountered during the actual installations.
The completion challenges included isolation of water production below the casing shoe and controlling condensate banking, sand production, and co-mingling multiple production zones in the long openhole sections.
A different type of completion that involved an expandable liner hanger (ELH) with an external-sleeve inflatable packer collar (ESIPC) was chosen and installation and cementing were accomplished in a single trip. The ESIPC was deployed just below the water-producing zone, and cement was pumped up the annulus from the ESIPC to where the expandable liner hanger (ELH) was set above it. This would prevent water from entering the wellbore while enabling optimum production. To prove the concept, a stack-up test was done at surface before actual deployment on location to ensure that the cement wiper plugs would pass through the expandable-liner-hanger ball seat and that the concept would perform as intended.
Swellable packers were selected from the various proven openhole isolation devices available to the industry to provide the zonal isolation required in the multi-zone intervals.
This was the first openhole completion in Southeast Asia in a high-temperature, commingled gas environment in which isolation would be contained solely by swellable packers.

Introduction
The Rong Doi (RD) and Rong Doi Tay (RDT) gas fields are offshore in approximately 85m of water. They are approximately 300 km southeast of Vung Tau, Vietnam (Fig 1). This high-temperature reservoir (300ºF) is within the Mid-Miocene Dua formation from 3050 to 3900 m true vertical depth sub sea (TVDSS).
The formation is an anticline with a four-way dip closure, split by three NNW-SSE sealing faults, and overlain by the Thong formation. Data from three offset wells; i.e., RD 1X drilled in 1994, RDT 1RX drilled in 1996, and RD 2X drilled in 1997, were available.
Guide line Systems for Deep Sea Deployment
Authors: Liu Francis C. 
Published: October 2008

INTRODUCTION

Definition
A guideline system consists of mechanical cables that restrict the lateral drifting of a payload suspended from a flexible lift line. The guideline system is composed of four basic components: surface support, guideline, anchor, and guide frame (Figure 1). The guideline is either a steel or a synthetic rope which stretches in a near vertical orientation between the surface support and the anchor. The guide frame is a rigid truss which maintains a fixed distance between the payload and the guideline. As the payload is raised or lowered by a lift line, the guide frame slides freely along the guideline. The lateral motion of payload is, thus, controlled by the guideline system. The number of guidelines in a system can vary from one to several depending on the degree of restriction of motion desired.

Objectives
The purpose of this investigation was to obtain a better understanding of the behavior of guideline systems by conducting controlled sea tests. It was intended to identify the difficulties and problems involved in hardware design, motion analysis, and at-sea operation. Once sufficient field data were obtained, then procedures for the design, deployment, and operation of guideline systems could be established for future projects.
The main emphasis of this study was on reducing the probability of guideline entanglement. Field tests were designed to show that with proper precautions, guideline systems could be operated without line entanglement. As a secondary interest, the mechanism of mating two structural modules on the seafloor by using a guideline system was studied. It was intended to demonstrate that the capacity of a gravity anchor could be increased by adding modular weights to the anchor after its implant, and that the alignment of the modules could be controlled by a properly designed guideline and bottom guide posts.

Background
Future underwater construction and salvage operations may require extensive load-handling capabilities for emplacement, suspension, recovery, and assembly of large, heavy structures at predetermined seafloor locations at depths to 20,000 feet. The required capabilities include not only high tension lifting but also seafloor positioning and mating. In general, new load-handling systems must minimize the dynamic loading in the lift line and the large amplitude oscillatory motion of the payload near the seafloor. Additional hardware is needed to provide the required capabilities for accurate seafloor positioning, precise alignment, and repeated returns to the same seafloor site. Guideline systems are a potential solution for these problems.
The concept of a flexible guideline system is simple and inexpensive; yet, it is an effective means of restricting the lateral motions of a payload throughout its vertical travel in the water column. The components of the system are readily available as off-the- shelf items. How ever, the most serious draw back to the system is believed to be its apparent low rehab1hty wh1ch 1S caused manly by line entanglement.
Greater Plutonio - Progressive Subsurface Management in a High Cost, Subsea Environment
Authors: Peak John 
Published: October 2008

Abstract
Greater Plutonio is BP's largest subsea development with an initial plan to drill and complete 43 high tech, high cost, high rate subsea development wells. A relatively low level of classical field appraisal was possible because of high industry costs coupled with the fast pace of the project. Innovative subsurface management has therefore been required to reduce substantial uncertainty during the development phase.
Full use has been made of excellent HiRes seismic data. An optimised well order has been crucial to reduce depth uncertainties and facilitate a focused, early data acquisition programme - while incrementally tackling more and more complex drilling and completion challenges. Extensive learnings have been possible from reservoir interference data resulting from rig-based production and injection tests.
The application of some specific technologies has been key to the success of the project: widespread use of a Subsea Acoustic Monitoring System to interrogate downhole pressure data from multiple offset wells prior to subsea system installation; 100% reliance on Subsea MultiPhase Flowmeters during initial ramp-up and subsequent operations; Extensive use of remote sensing technologies relayed real time to office desktops and fully integrated with well models to facilitate immediate well and reservoir management.
This has enabled significant reservoir learning and therefore reservoir management not only in the early ramp-up phase but actually before field start-up, which was achieved on 1st October 2007. In turn this has allowed the on-going development drilling order to be honed to maximise early production and injection.
The successful subsurface and wells management of Greater Plutonio has been demonstrated by the delivery of sufficient production potential to allow field rates of 200mbd in January 2008 (after just over 3 months of operations) and over 300mmscf/d of injection potential at the time of first gas injection less than 2 months after first oil. In addition, by early 2008 water injection had reached 120mbwd into 4 wells, with potential for a further 40mbwd already completed and tested.
Establishment of full voidage replacement in 2008 to allow sustainable plateau production is ahead of plan. The enhanced reservoir understanding from the pre-first oil and ramp-up data has reduced subsurface uncertainties while the Greater Plutonio development has progressed and will play a crucial part in increasing ultimate field recovery.
Geotechnical Design of Footings for Temporarily Founded Seabed Drilling Systems
Authors: Kelleher Patrick Joseph , Samsuri Nazri , Carter John 
Published: October 2008

Abstract
This paper describes some geotechnical aspects relevant to the design of a footings system used to support a seafloor-founded drilling rig. Once landed on the sea bed and isolated from vessel motions, adequate foundation support is required throughout the course of seabed operations - the duration of which may vary from hours to days, depending on the investigative work being undertaken.
The design requirements for footings supporting these systems are complex. Ideally, the design must:Provide sufficient bearing capacity on very soft seabed slopes of up to 20 degrees.Be resistant to damage in the event that the rig is landed on a stiff seabed.Minimise the surcharge applied to the seabed within the vicinity of the drill centre.Be resistant to seabed scour in prevailing currents.Provide adequate (temporary) support in the event of a shallow gas release.Minimize the breakout forces required during recovery from the sea bed.
All of the above issues were addressed in the design of a temporary footings system for a remotely operated, seafloor-founded, geotechnical drilling rig. This paper describes the observed performance of the prototype footings system that was deployed at a number of soft seabed locations offshore Korea, Western Australia and New Zealand. Recent enhancements to the design are also discussed.

Introduction
Seabed-founded geotechnical investigation rigs are increasingly being used in marine geotechnical site investigations. As investigations rapidly move to deeper waters and softer sea beds, the importance of adequately founding these devices has become critical. Inadequate design of the footings system supporting these devices will inevitably lead to:Poor borehole depth control (relative to the mudline);Potential rig instability (particularly on seabed slopes, and under the dynamic loading associated with seabed drilling operations); andThe mobilisation of excessive breakout forces during recovery from the sea bed.
Most geotechnical sampling and testing equipment requires some interaction with the seabed during the course of a seabed investigation. Properly compensated heave compensation systems typically rely on a stiff link between the moving vessel and the seabed to provide a datum point for the motion control systems. (This is generally achieved by founding a heavy seabed template on the seabed prior to drilling). Single stroke reaction frames and remotely operated seabed drill rigs need to land and remain stable on the upper seabed layers during seabed operations.
Technically superior landing and leveling systems have recently been developed to provide better stability and control of seabed-founded drill rigs, even on very soft seabeds that are typically encountered at deepwater sites. This paper describes the design and field testing of such a system, that has provided support and stability to a seabed founded drilling rig at a range of deepwater seabed sites.
Electrohydraulie Hardline MuItiplex Contral System for BOPT'S
Authors: Henry M. 
Published: October 2008

ABSTRACT
Fifteen million sq miles of sedimentary basins lie between 1,000 ft and 10,000 ft. Drilling and production in increasing water depth will demand an equally increasing reliability of the subsea equipment; components must be as autonomous and separate as possible so that the failure of one of them does not endanger the whole assembly; link between the surface and the subsea equipment must be reduced as much as it can be due to their vulnerability.
Previous subsea blowout presenter systems, whether fully hydraulic or electro hydraulic, are using multisided and require large-diameter expensive and troublesome umbilical?s. Now the industry has available a remote control system for BOP's stack in deep-sea drilling operations that only requires a pair of wires coupled with two hard line multiplex electronic units.
A backup acoustic control system is also attached to the main system, in order to undertake the main function in case of accident on the multiplexed cable. As for the hydraulic energy, it can be pumped from the surface as usual, or directly produced on the stab assembly by means of a subsea hydraulic power unit in closed circuit.
The MATRA Bops? remote control system is designed according to 10,000-ft water-depth specifications. Two hard line multiplex electronic systems (TESUMA) give full redundancy to the control, and an acoustic system (TELTAC) is used as a backup, in case of emergency. Two independent electro hydraulic units, directly connected to each hard line multiplex, deliver the necessary power to the presenters.

INTRODUCTION
A typical BOP stack consists of a certain number of organs hydraulically operated such as: connectors, rams, wedge locks, annular presenter, choke and line valve operators, and so on. The operation of most of these organs should be made in limited time (4s to 20s) at a pressure of 1,500 psi above the ambient pressure. Other organs, such as bag-type BOP and ball joint, should have a pressure regulated from 1,500 to 3,000 psi.
The operation of the stack is insured by two hydraulic units, coded yellow and blue, located on the stab assembly. Each unit consists of a bank of accumulators and an electro hydraulic block. The two sets of accumulators normally isolated can be remotely coupled. The total useful capacity of hydraulic fluid allows one full cycle of all stack function operations, plus an additional availability of 25 percent of the operating volume with a pressure decrease from 3,000 to 1,200 psi over ambient.
The subsea accumulators are of the bladder type in cylindrical shape.
There is no possible absorption of the nitrogen precharged by the fluid. Recharge is currently 1,000 psi above ambient hydrostatic exhaust pressure, the minimum pressure being then 1.2 times the recharged pressure and the maximum pressure: 3, 000 psi over.
The capacity of each accumulator ranges from 12.5 to 50 gal and provides approximately between 0.25 for 10,000 ft and half volume for 1,000 ft of useful fluid.