bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Research Path to Determining the Resource Potential of Marine Gas Hydrates
Authors: Boswell Ray , Rose Kelly , Baker Richard 
Published: October 2008

Abstract
A primary goal of the U.S. National Interagency Gas Hydrates R&D program is to determine the natural gas production potential of marine gas hydrates. In pursuing this goal, four primary areas of effort are being conducted in parallel. First, are wide-ranging basic scientific investigations in both the laboratory and in the field designed to advance the understanding of the nature and behavior of gas hydrate bearing sediments (GHBS). This multi-disciplinary work has wide-ranging direct applications to resource recovery, including assisting the development of exploration and production technologies through better rock physics models for GHBS and also in providing key data for numerical simulations of productivity, reservoir geomechanical response, and other phenomena. In addition, fundamental science efforts are essential to developing a fuller understanding of the role gas hydrates play in the natural environment and the potential environmental implications of gas hydrate production, a critical precursor to commercial extraction. A second area of effort is the confirmation of resource presence and viability via a series of multi-well marine drilling expeditions. The collection of data in the field is essential to further clarifying what proportion of the likely immense in-place marine gas hydrate resource exists in accumulations of sufficient quality to represent potential commercial production prospects. A third research focus area is the integration of geologic, geophysical, and geochemical field data into an effective suite of exploration tools that can support the delineation and characterization commercial gas hydrate prospects prior to drilling. The fourth primary research focus is the development and testing of well-based extraction technologies (including drilling, completion, stimulation and production) that can safely deliver commercial gas production rates from gas hydrate reservoirs in a variety of settings. Initial efforts will take advantage of the relatively favorable economics of conducting production tests in Arctic gas-hydrate bearing sandstones with the intent of translating the knowledge gained to later testing in marine sandstone reservoirs. The full and concurrent pusuit of each of these research topics is essential to the determining the future production potential of naturally-occuring gas hydrates.

Introduction
Gas hydrates are a naturally occurring substance that can be found in nature wherever water exists in combination with sufficient volumes of appropriately-sized gas molecules under specific high-pressure, low-temperature conditions (Sloan and Koh, 2007). These conditions are restricted primarily to arctic regions, deep lakes, and marine continental shelves in water depth of ~500 m or more. Additional factors that influence the occurrence and nature of gas hydrates include the mineralogy and petrophysical characteristics of the host lithology, and the chemistry of both the gases and the water.
Multidimensional Simulations of Multiphase Flow for Improved Design and Management of Production and Processing Operation
Authors: Laux Harald , Meese Ernst , Mo Sjur , Unander Tor Erling , Johansen Stein Tore , Bansal Krishan M. , Danielson Thomas John , Goldszal Alexandre , Monsen Jon Ingar 
Published: October 2008

Abstract
Over the past five years, ConocoPhillips, TOTAL, and SINTEF have developed a novel transient multiphase flow simulator, called LedaFlow, with both one- and multi-dimensional capabilities. The aim of the development is to meet industry needs for improved simulation of fluids management and related flow assurance issues in oil/gas production and processing operations. LedaFlow is composed of a suite of models, including a complete one-dimensional transient model with compositional tracking, a complex network solver, and algorithms to couple models of different dimensions. The transient multi-dimensional model offers detailed flow distributions that are impossible to obtain with one-dimensional models. It was demonstrated recently that flow regime transitions, observed pressure gradients and liquid holdup can be accurately reproduced (Laux et al., 2007).
In the present paper, we analyze 2-phase flows in vertical risers and demonstrate the capabilities of multi-dimensional modeling. The prediction of vertical flows are very good except for low flow rates. We demonstrate that complex flow regimes (such as churn flow) are predicted with the LedaFlow quasi three dimensional (Q3D) model, without resorting to assumptions about flow regimes and structures. Q3D simulations show that small deviations from perfectly vertical flow may have a large effect on liquid hold-up and pressure drop. The Q3D model is furthermore applied to simulate an operational situation where fluids are displaced to prevent hydrate formation during shut-down.

Introduction
Using the LedaFlow quasi three-dimensional (Q3D) model it is possible to predict complex flow regimes such as gravity-induced and hydrodynamic slugging, as well as transitional flow (between wavy stratified and slug flow) in pipelines (Laux et al. 2008). Prediction results for wavy stratified flow is presented in Laux et al. (2007). In this paper, we address churn flow in vertical and deviated risers as well as fluid displacement to prevent hydrate formation during a shut-down situation. For multiphase flow in risers and wells, flow regimes are often very complex and can not be treated satisfactorily with 1D models.
One-dimensional (1D) models have been developed over the last 50 years to predict multiphase flows in pipelines. These models have been successful in assisting the industrial development but still have significant shortcomings due to simplifications and the use of empirical correlations. At the same time, new three-dimensional (3D) modeling techniques are developing fast, made possible by the continuous growth in available computational power. 3D Computational Fluid Dynamics (CFD) models can give information that both qualitatively and even quantitatively surpasses information obtained from 1D models.
4C Fiber-optic Permanent Installed Sensor Cable for Seismic Reservoir Monitoring.
Authors: Bunn Brett 
Published: October 2008

Abstract
Recent advances in fiber optic sensing technology have provided the oilfield service industry with a new tool for reservoir monitoring in deep water. A fiber optic 4C Permanent seabed cable has been successfully demonstrated in the GoM. Advances in the cable design and optical sensors, including a 3-axis optical accelerometer, have turned this system into a practical tool for 4C permanent reservoir monitoring. The cable design and performance of the new system are reviewed. An 800 m cable with 4C sensor stations located every 50 m was tested along side a 4C cable with conventional electrical sensors. While the cable tested was limited in size, we have demonstrated the optical systems capabilities beyond 3000 m depth and with channel counts in excess of 2000 over 12 km in the lab. Data collected from the field tests have proven the prototype optical system meets the performance required of the deepwater permanent reservoir monitoring. The test results presented herein were acquired in during a development project with Chevron. Current projects include pilot test on active reservoirs and we will report the current status and test reports as available.

Introduction
Traditional seismic acquisition hardware relies on sensors that produce an output voltage that is amplified, multiplexed and transmitted up a cable to the recording system using distributed in-sea electronic circuit cards and modules. The passive nature of the optical telemetry system eliminates the need for costly in-sea electronics and the problems associated with them, providing a more reliable, less expensive, safer system to deploy and operate. Optical sensor based systems are ready to replace the traditional technology in the oil field, this is already being seen in the low channel count high stress environments of temperature and pressure sensing in-well. Advances in PGS optical technology provides a system that is expandable beyond the capabilities of current seismic systems.
Optical sensors used in acquiring seismic data are typically constructed from optical interferometers. In this paper we present the seabed system that was tested in the Gulf of Mexico summer 2006, we describe the cable and sensor construction, the optoelectronic system and the recording interface. We also compare the data quality between the electrical and the fiber optic cables.

The fiber optic system
The cable utilizes a Dense Wavelength Division Multiplexing (DWDM) telemetry scheme to optically power the sensors. An optoelectronic cabinet and recording system provides the optical signal to the passive optical network of sensors. The basics of the system include a frequency-modulated laser source passing through an interferometer, where stress from the outside environment causes a phase shift in the light as it passes through the interferometer. The light is then detected and the phase information extracted to output a signal equivalent to the input stress.
The Motor Jacket: An Innovative System for ESP PCP Efficiency Improvement in Heavy Oil Reservoirs
Authors: Tealdi Loris , Rampoldi Maurizio , Malonga Henri , Okassa Fabrice , Obondoko Gaston 
Published: October 2008

Abstract
Production of heavy oil with an artificial lift system is a puzzling problem due the hydrodynamic conditions prevailing inside and surrounding the pumping system. The aim of this paper is to present an application on ESP PCP of a system that has an impact on the oil viscosity surrounding the ESP PCP unit and as a consequence improving the production performance, the ESP PCP pump efficiency and run-life. The theory is based on the impact of convection currents on the diffusion of the temperature in high viscous oil inside a pipe. A case history will be presented on the ZAM-408ML, a TAML6 multilateral well producing from level B of the Zatchi field, offshore Congo.

Introduction
Zatchi Marine is an offshore field located about 25 km from the Congolese coast (fig.1). The field, developed in 1980 presents 5 oil bearing levels named A, B, C, D and E. Level A has currently no economical value since it is gas bearing. While the oil bearing levels C, D, E are producing from several years, level B, after very short episodes of production in the past was put in production in 2007 via the multilateral well ZAM-408ML. The level B, object of the paper, is a complex heavy oil reservoir with a primary gas cap and the presence of a bottom aquifer. The oil has a very high density (15°API) and is very viscous (13000 cP @ 34.5°C) probably due to the low reservoir temperature (about 35°C). This level is composed of sand, shaly sand, dolomite and shale (fig.2). The average reservoir permeability is greater than 1Darcy.
Three wells have been drilled in the B level since 1991: the first one, ZAM-116 (vertical well with conventional completion), produced a maximum of 130 bopd (lifted by a sucker rod pump with a surface motor); thereafter, the ZAM-406 (horizontal well) produced at the beginning 440 bopd but the oil rate dropped rapidly due to a severe gas coning phenomena; the last one, ZAM-111ST (horinzontal well), peaked briefly up to 285 bopd. This brief overview depicts the reservoir B production complexities which in summary:the heaviness and the viscosity of the oil,The severe problems of gas coning and cresting which reduced drastically the progressive cavity pump efficiency.
The multilateral well ZAM-408ML represents the forth well which is attempting the production of such reservoir. The well architecture and trajectory was designed to optimize reservoir recovery, productivity index while reducing the drawdown at the wellbore to avoid gas coning phenomena. In parallel, it has been decided to develop an innovative system to improve the ESPCP performances by increasing and homogenising the temperature distribution around the artificial system planned to be installed. The original scope was not to improve the well productivity, but only to have a better handling of the flow at the pump interface and maximizing the pump efficiency.
New Approach to Sand Removal
Authors: Coffee Stephen Douglas 
Published: October 2008

Abstract
This paper presents an enhanced design approach for sand removal systems and produced water treatment systems as well as lessons learned from pilot studies and installations on semi-submersible platforms and FPSO platforms in the Campos Basin.
Reduction of residence time and loss of production due to the accumulation of sand in production separators is a recognized problem worldwide. Interruption of production for removal of accumulated sand in production separators, abrasion to pumps, valves, and accessories, as well as the risk of oil production loss can be greatly reduced or eliminated by a new approach by continuously desanding production separators. Test and field experience shows how this approach can effectively be applied to any production separator or vessel where sand is produced and where space is limited.
Occupying a small amount of space, the system discussed (which includes a desander, solids collection vessel and eductors) continually cleans the production separator while desanding and collecting sand in a contained system. This approach, offering superior desanding efficiency, greatly decreases the inherent problems of formation sand at the surface by eliminating interruptions in production due to sand removal and repairs caused by sand, as well as collects the sand in an easier, cleaner, and dryer (more oil free) state.
Kikeh Development: Project Overview
Authors: Shahruddin Tengku Saifuzzaman , Jenkins Roger William , McFadyen Michael Keith , Dechant Steve , Weber John D. 
Published: October 2008

Abstract
Kikeh is Malaysia's first offshore deepwater development. Located in the South China Sea offshore the east Malaysian state of Sabah, the Kikeh oilfield lies in average water depths of 1,320 meters. With recoverable reserves in excess of 400 million barrels of oil, it is expected to achieve a plateau production rate of 120,000 barrels per day. This discovery in Block K was made in August 2002, with production initiated in August 2007. The development incorporates a Spar as well as a subsea water injection and production system that is connected to a Floating Production Storage and Offloading (FPSO) vessel. Kikeh is planned to be developed utilizing 34 wells.
This paper aims to present a general overview of the Kikeh project and describe the numerous innovations that were incorporated into it.

Introduction
In 1999, Murphy acquired the rights to explore the deepwater Block K, offshore the eastern state of Sabah, Malaysia, as shown in Figure 1. The block encompasses an area of 4,111 km2, in water depths ranging from 1,300 m to 1,400 m.
Kikeh Development: Project Execution Model
Authors: Dechant Steve , McFadyen Michael Keith 
Published: October 2008

Abstract
The Kikeh Development is the first deepwater project in Malaysia and is located offshore Eastern Malaysia in the South China Sea in water depth of 1320 meters. Kikeh is produced via a Spar and a subsea production system back to a Floating Production Storage and Offloading (FPSO) unit. Water injection to wells at both the Spar and subsea are used for reservoir pressure maintenance. Kikeh is planned to be developed with 34 wells. Production from the Kikeh Field commenced in August 2007.
Highlights of the Kikeh Development include:Discovery to First Oil in only five yearsFirst deepwater development offshore MalaysiaFirst Spar constructed in Malaysia and the first installed outside the Gulf of MexicoFirst topsides floatover onto a SparFirst turret-moored FPSO in conjunction with a SparFirst use of a tender assisted drilling rig on a SparFirst mid-water high pressure flowline
This paper will provide a summary of the overall Project Execution Strategy and Contracting Plan and will highlight the small team approach adopted by Murphy Oil. It will also initially discuss the challenges of the parallel appraisal / development approach required to accomplish first-oil from the Kikeh Field in five years. Lessons Learned will also be provided.

Introduction
The Kikeh Field was discovered on July 30, 2002 by Murphy Sabah Oil Ltd. It was Murphy's third deepwater well offshore Malaysia and it was immediately believed to be a major discovery. Two additional wells were drilled in the second half of 2002 to confirm the discovery and by the end of 2002 the Kikeh Field had been confirmed. Initial estimates placed the recoverable reserves in excess of 400 million barrels of high quality crude oil.
The Kikeh Field is located 120 km northwest of the island of Labuan, offshore Sabah, East Malaysia and lies in water depths of approximately 1,320 meters (Figure 1). The reservoir consists of multiple sand horizons that are relatively shallow at 2500 - 3050 m. Murphy Oil is the operator of the Block and is responsible for managing the appraisal, execution and operation of the Kikeh Field.
Technical Challenges and Production Forecast for Subsea Compression System
Authors: Oiungen Bjorn , Solvik Johan , Morgan Rhodri 
Published: October 2008

Abstract
This paper identifies areas of uncertainty related to the new subsea compression technology. In addition, a description of an approach used to support the decision-making process from idea to commercialization of any subsea production and processing system is presented.
Today, subsea production and compression systems are given more attention than ever before. Common for all new installations is the increasing demand for production efficiency and reliability. This paper presents a method for qualification and production forecast, applicable to all subsea production and processing systems.
The study case is a subsea production system where the gas tie-ins will, in near future, face a minimum flow problem due to glycol accumulation in pipelines, which will have a major impact on the production capacity. Subsea compression is one of the solutions being evaluated as a mean to prevent the reduced well flow. Subsea compression is currently a novel and unproven technology, but with great potential to reducing capital and operational expenditures, contra a topside solution. To capture this potential, technology qualification analyses are required to evaluate the technical feasibility and risks associated with the compression alternatives. In order to reveal technical uncertainties, a detailed failure mode identification and risk ranking of the new technology has been performed.
The challenges involved in the delivery of such a system will revolve around the engineering of a system containing a high voltage electrical distribution system over a long step out and high speed rotating equipment, as well as the implementation of new subsea technologies such as magnetic bearing systems. Specific risks to the system arise from the breakdown in electrical devices due to the harsh environmental conditions of temperature and possible presence of process fluids.
Compared to a topside facility, production forecast analyses have shown that a subsea processing unit has an equivalent potential to preserve high system availability.
Fluid and Gas Expulsion: Impacts on Seafloor Geology and Biology
Authors: Roberts Harry H. , Hunt Jesse L. , Shedd William W. 
Published: October 2008

Abstract
The northern Gulf of Mexico continental slope is the most thoroughly imaged and studies continental slope in today's oceans. The entire slope is covered with 3D-seismic and much of the area has been imaged with higher resolution acoustic systems. These data describe a complex seafloor impacted by fluid-gas expulsion. Alvin dives in 2006 and ROV Jason dives in 2007 have produced seabed observations and samples that have greatly improved our understanding of cross-slope and along-slope distribution and variability in biologic communities and their hydrocarbon seep related habitats. Site selection for the 2006 Alvin dives was accomplished though surface reflectivity analysis of the MMS slope-wide 3-D seismic database followed by photo reconnaissance. From 80 potential sites, 20 were subjected to photo reconnaissance from which 10 sites were selected for Alvin dives. Four sites, found in AC 818, AC 601, GC 852 and AT 340 had impressive and diverse chemosynthetic communities as well as well-defined fluid-gas expulsion geology. In addition to chemosynthetic communities, GC 852 had abundant hard and soft corals seated on substrates of authigenic carbonate boulders. At AC 601 (WD ~ 2340 m) a brine lake (4 m deep and 180 m wide, salinity ~ 90 ‰) was investigated and sampled. White " flocs?? floating in the brine and concentrated at the " shoreline?? were found to be barite. No visible animal life was observed in the brine. Isolated living communities of mussels and urchins were found on the lake margins. Geochemically, the water column methane concentration above the lake exceeded all other Alvin dive sites by an order of magnitude. Methane was supersaturated all the way to the surface, suggesting the site could be a source of methane to the atmosphere. At the four key sample locations Autonomous Ultrawater Vehicle (AUV) data were acquired prior to the 2007 ROV Jason cruise. Multibeam bathymetry from the AUV was used as a navigation underlay for detailed sampling by Jason. Depth and geographic ranges for key components of chemosynthetic communities were improved and our understanding of the geologic aspects of hydrocarbon seep habitats was significantly advanced by data from the 2006 and 2007 dives.