bluuebunny/crossref_metadata_2025 huggingface dataset:
Feasibility Assessment of a Mid-Water Transfer System
Authors: de Abreu Alvim Roberto , Elman Priscilla
Published: October 2008

The development of deepwater oil fields based on a production platform with dry trees, connected to a Floating Production Storage and Offloading (FPSO) vessel, has proved to be technically and economically attractive. However, a key issue for the practical implementation of this production concept is the availability of a cost-effective oil and gas transfer riser solution.

The use of conventional catenary or self-standing riser technologies is sometimes avoided by operators due to high costs and flow assurance issues. To counter these problems operators are seeking a cost-effective solution for fluid transportation between two vessels at a water depth close to the surface. This type of riser system has been used successfully in benign environments like West Africa and is now being considered for harsher environments such as offshore Brazil.

2H Offshore conducted a preliminary feasibility study encompassing installation and in-service dynamic response, to prove the technical feasibility of a system composed of a group of large diameter free-hanging flexible pipes, required to connect two platforms offshore Brazil.

The paper demonstrates that this configuration is practical and simple because it can be designed with regular flexible pipe and standard components. Additionally, it can be deployed using conventional flexible pipe laying vessels.

Introduction

The design of a riser solution to connect a spread moored Floating Production Storage and Offloading vessel with a dry completion platform (Tensioned Leg Wellhead Platform - TLWP) is a complex engineering process which is being sought by operators as a novel and cost effective solution for fluid transportation.

The objective is to transfer the produced oil from the TLWP to the FPSO for processing, storage and later off-loading to a shuttle vessel. Additionally water is injected from the FPSO back to the TLWP and into the wells. This type of system has been proposed by several companies and is referred to as a " Mid-Water Transfer System??, hereinafter referred to as MWTS.

Due to the increasing demand for riser solutions in deep water developments, the use of conventional catenary risers (Flexible/SCRs) or Free Standing Hybrid Riser (FSHR) technologies, are sometimes avoided due to their cost. This paper evaluates a novel and cost effective solution for fluid transportation between the two rigs, considering flexible risers which are suspended close to the water surface. This allows the use of cheaper flexible risers with low collapse pressure limits which, reduces the cost of the riser system.

2H Offshore has conducted a preliminary feasibility study to prove the technical feasibility of a system composed of a group of large diameter free-hanging flexible pipes required to connect two platforms in offshore Brazil. The study covers the installation, in-service dynamic response and slugging behaviour of the system.
Coupled Soil Deformation-Flow-Thermal Analysis of Methane Production in Layered Methane Hydrate Soils
Authors: Ng Albert , Klar Assaf , Soga Kenichi
Published: October 2008

A potential of methane hydrate to be an alternative energy resource has triggered numerous researches to investigate the physical, chemical and mechanical properties of methane hydrate bearing soils. Among various issues, geotechnical characterization of methane-hydrate soil is particularly important. For example, depressurization process used for methane gas extraction significantly changes the stress state and the mechanical properties of hydrate soils, which may lead to potential geotechnical hazards such as submarine landslide or wellbore collapse. At present, most of the geotechnical analyses associated with methane gas extraction assume that depressurization of methane hydrate happens in a homogeneous hydrate soil layer. This paper presents results of the analyses of methane hydrate extraction in alternating layers of clay and hydrate-bearing sand, which are encountered in the Nankai Trough. Using a coupled deformation-flow-thermal code implemented in FLAC, the methane gas extraction process in such soil conditions is simulated. Results show that heat flows from the clay layer to the sand layer leads to faster rate of hydrate dissociation in the hydrate region near the clay/sand boundary than at the center of the hydrate-sand layer, which influences stress distribution around the wellbore. As the soil relaxes toward the wellbore, arching effect in the vertical plane can be seen in the sand layer in addition to the usual increase in the circumferential stress. This is due to the force transfer from the casing to the clay layer, which deforms greater than the sand layer during depressurization. The thickness of the layered soils is also varied and it is demonstrated that the heat flow from the interface has a greater effect in the case of a smaller thickness of the clay-sand layer. Consequently, the arching effect and vertical compression are more prominent inside such case. The above findings highlight the importance of understanding geotechnical characteristics of methane hydrate soil in production.

Introduction

Methane hydrate is an ice like solid material composed of a gas molecule caged in a structure made of water molecules, and its natural form only exists under high pressure and low temperature condition, i.e. permafrost regions or beneath deep seabed. It is formed inside soil pores and it will dissociate into methane gas and water if the stable temperature-pressure equilibrium is breached. Sites with high concentration of methane hydrate are considered to be a possible energy resource for future years. This has triggered numerous researches to investigate the physical, chemical and mechanical properties of methane hydrate soils. Two methods are generally accepted to be feasible for dissociating methane hydrate and hence extracting methane gas in situ:the use of depressurized wells, which reduce the pressure in the soil around the wells, andthe use of thermal injection wells, which increase the temperature in the surrounding soil by injecting hot fluid.
Structural Design Overview of the Drill Ships
Authors: Lim Yu Chang , Moon Hae Am , Kim Jin Tae , Kim Jong Ku
Published: October 2008

Daewoo Shipbuilding and Marine Engineering (DSME) was awarded the contract to build four drillships capable of drilling up to 30,000 feet in 10,000 feet water depth and scheduled for delivery by mid September 2008. The structural design of the drillships was based on the operating experience of the owner Transocean Offshore Deepwater Drilling Inc, and takes into account the new requirements of DnV OS Rules and CSA2 guidelines.

The former are based on Load and Resistance Factor (LRFD) format, which is different from the other conventional approach, Working Stress Design (WSD). Whole ship analysis was performed. The overall structural design procedures for the drillships are presented and recommendations are proposed in the paper. Other features of the structural design process including the fatigue assessment and accidental load assessments are presented.

Structural Design Basis.

According to COMPANY and Class requirements, the following design concepts for the Hull structural strength evaluation was considered.

1A1

This is the main class requirement with which all ocean going vessel should comply. The details of the requirement are specified in Ship Vessel Rule.

The main class requirements met through local scantling by ‘DNV/Nauticus Hull' and hold FE analysis based on Classification Notes 31.3 Strength Analysis of Hull Structures in Tankers

OS-C102

DNV OS-C102 specifies that offshore ships are to be designed to comply with LRFD design concept as defined in OS-C101 as well as main class requirements. It is to be noted, however, that the severity of onsite environmental loadings determined whether to apply the LRFD design concept. The subject vessel was assumed to be operating in relatively harsh environment for which the LRFD was mandatory to be applied. The subsequent chapters was prepared on this assumption.

The requirement specified three limit states in its details:ULS (Ultimate Limit State)FLS (Fatigue Limit State)ALS (Accidental Limit State)

The capacity assessment in the ULS condition included buckling and yield checks. Gross scantlings were utilized in the calculation of the buckling capacity of the hull structural elements. The strength of the hull girder was assessed based on the load conditions that result in maximum longitudinal tension and compression stresses in deck and bottom plating. The strength of the supporting structure for the topside facilities was evaluated considering relevant operational load conditions and their combinations. The local requirements for the structural members in the fore and aft ship including deck houses and accommodation were designed to comply with the technical requirements given in the Rules for Classification of Ships Pt.3 Ch.1.
Lightening the Load (LNG)
Authors: Gilchrist Robert
Published: October 2008

Introduction

There are a number of motivators driving LNG side-by-side as a cargo transfer option, not least the success of floating solu-tions in Oil and LPG production projects. The main problem faced is that present LNG ships are designed for conventional manifold loading only. This, coupled with the fact that suitable floating LNG hoses only being in the early stage of develop-ment, ensure that tandem loading is not an option at this time.

We also have the situation where it is increasingly difficult to build a shore terminal for receiving Bulk LNG. Ports big enough for the ships are increasingly congested and bulk LNG terminals have strict HSE requirements. The option of having Floating Storage and Regasification Units (FSRUs) situated offshore but near to the ports, offers a solution that is being ex-plored by a number of importers. This again will require side-by-side for discharge, as the gas will increasingly come from the spot market on standard long-haul vessels.

With FPSO LNG projects now coming off the drawing boards and going into the yards, companies have to be certain of the capabilities of the Ship-to-Ship (STS) Industry. STS Service Providers need to use their experience to provide an operational envelope that makes the economics work.

Historically, Ship to Ship Transfers were generally considered something of a ‘risky’ operation, only carried out when abso-lutely necessary. There is now a growing confidence that the STS Industry today can deliver a high quality, repeatable opera-tion and meet the high safety standards expected in the LNG Industry.
The StatoilHydro IOR Program
Authors: Jorgenvag Astrid H. , Sagli Jan Richard
Published: October 2008

The paper includes:A brief introduction to the main technologies being developed and implemented in StatoilHydro's IOR R&D program.An evaluation of how the technologies will influence on the recovery from the company's existing fields

StatoilHydro will give a brief introduction to how the company envisages fulfilling the demanding requirements to significantly improve the oil recovery from producing fields. StatoilHydro's recoveries are favourably compared to other operators. The paper will put the presented technologies and methods into the IOR perspective.

StatoilHydro has traditionally had its focus on the Norwegian Continental Shelf (NCS). The focus is now turning towards deeper waters like the Gulf of Mexico, and arctic areas. This means that it is crucial that technologies that are being developed should be suited also for these fields.

Introduction

As a mean to meet the StatoilHydro business challenge of " Increasing the value of existing business and secure platform for further growth??, the Improved Oil Recovery (IOR) research programme was established after the merger of Statoil and Hydro Oil & Gas in October 2007. Based on the subsurface activities from the former Statoil research programmes SIOR and TAIL, together with Hydro's IOR programme, a large and powerful R&D programme, including geophysics, reservoir, drilling, well and production technology was formed.

The IOR programme was established to supply StatoilHydro's assets with critical technology and work processes in order to achieve a world class recovery factor from all relevant areas. A good collaboration model with the relevant business area in the company has been established.

The StatoilHydro assets on the NCS are in a situation where new technology is required " today?? to maintain the production level. This applies in particular to the mature fields like Heidrun, Gullfaks, Snorre, Brage and Oseberg. The somewhat younger subsea fields will within a few years be in a similar situation. It is of high importance to develop the technology needed in due time to make use of the existing infrastructure.

StatoilHydro has a high focus on the Gulf of Mexico (GoM), where deep water technology will be essential. StatoilHydro does not have any leading position in deep waters today and new technologies both within solutions for field development as well as for reservoir management will be crucial to achieve a sound economic result of the investments. Most of the efforts on shallow waters will be directly relevant also for deep water applications. The increased focus on carbonate reservoirs from the portfolio outside the NCS requires new competence and technology.
The Research Path to Determining the Resource Potential of Marine Gas Hydrates
Authors: Boswell Ray , Rose Kelly , Baker Richard
Published: October 2008

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

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

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

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

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

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

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

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

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.
A Novel Method For Coiled Tubing Installation
Authors: Simpson Pete , Hatton Stephen
Published: October 2008

Installation of flexible pipe for offshore developments is costly due to both the physical cost of the flexible pipe, and the expensive day rates and availability of suitable installation vessels. Considering the scarcity of flexible pipe in today's increasingly demanding and busy market, operators are seeking a cost effective solution for installing piping in a range of water depths using vessels which are readily on hand.

This paper describes a novel approach to installing reeled coiled tubing, from 1inch to 5inch diameter, from the back of a small vessel in water depths from 40m up to around 1000m. The novelty of the system is the fact that the equipment design allows it to be installed on even relatively small vessels of opportunity, such as anchor handling or installation vessels, from smaller, and cheaper quayside locations. Such an approach is the ideal solution to the problem faced by operators, in that it allows the installation of cheaper, readily available coiled tubing, from cheaper and more readily available vessels.

Introduction

Flexible pipe technology has developed rapidly in order to meet the increasingly demanding requirements of the offshore industry. As offshore developments have progressed into deeper and more demanding environments, flexible pipe manufacturers have been pressing to provide new flexible pipe technologies suitable to the task.

The natural advantages of flexible pipe over rigid pipelines make it the preferred solution for many shallow water developments, however, its convenience means that there is enormous demand for the product. Such is the market's demand for flexible pipe that flexible pipe factories are working at maximum production and long lead times and high prices are commonplace. Once produced, the pipe still needs to be installed and the available installation vessels are not only expensive, they are usually operating on long term contracts and must be booked months or years in advance.

However, there is an alternative to using flexible pipe for some offshore situations. Coiled tubing is a proven technology which has largely been forgotten by the industry after the advent of flexible pipe technology. This paper shows how it is still a viable and attractive alternative to flexible pipe, and can be installed cheaply and easily from the back of small vessels of opportunity.

Introduction to Coiled Tubing

As long ago as 1944 engineers were faced with deploying subsea pipelines using a reliable and easily deployable design. The project in question was how to supply the allied army with fuel oil after the D-day invasion. The pipes needed to be installed in as short amount of time possible after D-day, using whatever vessels and crew were available. The solution devised by British engineers was to lay twenty three 3?? pipelines across the English channel, varying from 30 to 70miles long (48km to 113km). The pipe was made in 4000ft (1219m) sections, butt welded together, stored in spools and deployed across the English channel.
LNG Imports Into North America and Implications
Authors: Juden Mike , Inglesby Tommy , Bodden Stuart
Published: October 2008

The need for LNG to fill the natural gas supply gap in North America may increase dramatically to 2015 and beyond as natural gas demand increases at rates higher than most observers expect. Developing CO2 legislation, increasingly advantaged gas-fired generation, oil sands demand, and biofuels demand could drive a greater than expected demand for natural gas domestically, with LNG imports expected to fill the gap.

However, LNG liquefaction is expected to continue to be short to 2015 and beyond. These shortages are driven by increasing liquefaction costs, contractor/crew shortages, reserve access issues, project delays, and the often overlooked increasing domestic demand in the LNG exporting counties. Increasingly, LNG contracts will include flexible diversion clauses allowing movement of LNG supplies to markets other than originally contracted markets. Although there is some baseloaded North American LNG, significant LNG is attracted to North American regas based on price/producer-net-backs when other regions have adequate supplies to meet needs. The trend toward greater LNG flexibility could strengthen the linkage in North American natural gas pricing to alternate fuels through competition with Europe for LNG volumes priced at residual fuel oil and eventually with Asian crude-linked LNG.

North America will compete with Europe and Asia for marginal LNG supplies unless European end users have over-contracted for LNG, which may well be the case. European and Asian end users, with based-loaded LNG, will retain LNG supplies, when needed, to fill supply needs irrespective of price. Over-contracted European LNG, if it were to flow to North America, would represent approximately 10 percent or more of U.S. and Canadian demand in 2010 and would go a long way in meeting a potential supply short-fall. With LNG at the margin, mechanisms impacting the level of North American LNG imports influence natural gas pricing, which in turn impacts gas producer and power generator profitability and company valuations.

Introduction

North American natural gas demand, domestic supply, natural gas price setting mechanisms, Atlantic Basin pricing dynamics, and contracting regulations and practices for electric and natural gas utilities all impact the level of LNG imported into North America. The resulting flows of LNG, especially into the U.S., have very significant implications for the global LNG trade, as well as substantial and far-reaching implications for producers, LNG developers, end users, and policy-makers.
Predicting When and Where Hydrate Plugs Form in Oil-Dominated Flowlines
Authors: Boxall John , Davies Simon , Koh Carolyn Ann , Sloan E. Dendy
Published: October 2008

This work provides a means to predict when and where hydrate plugs will form in oil-dominated flowlines. The method was funded by DeepStar and is based on a hydrate kinetic model, CSMHyK, developed over the last six years, which is currently an addition to the transient multiphase program OLGA by SPT (Scandpower) Inc. The predictions show good agreement to data for hydrate formation in three flowloops with five oils.

Recent CSMHyK-OLGA workshops have been held in Houston and Oslo, and major companies are beginning to use the program in flow assurance to predict where and when hydrate plugs will form in flowlines.

Introduction

Gas and oil sub sea production and transportation are moving to deeper developments where the temperature and pressure conditions are well within the hydrate stability region. The subsequent increased risk of hydrate formation requires new strategies in flow assurance. Traditional methods of thermodynamic avoidance are impractical or uneconomic due to the large amounts of thermodynamic inhibitor (e.g. methanol or monoethylene glycol) required to prevent hydrates from forming under these conditions [1, 2]. Transient operations are particularly problematic due to the temporarily extreme subcoolings under these conditions. The prediction of hydrate formation rates in these conditions is a major challenge requiring knowledge of the kinetics of hydrate formation, rather than only hydrate thermodynamics. The ability to predict the rate of hydrate formation in sub sea flowlines under restart and shutdown conditions is extremely valuable in establishing new operating procedures during transient operations and in flowline design.

CSMHyK is a subroutine module for the OLGA (SPT Group) multiphase flow simulator. Researchers at CSM in cooperation with the SPT Group have been developing the module since 2003. The model predicts the rate of hydrate formation using a first-order rate equation based on the thermal driving force. The rate equation was originally proposed by Vysniauskas and Bishnoi [3] in the absence of mass and heat transfer limitations. In order to accurately simulate hydrate formation in flowloops, it was necessary to reduce the intrinsic kinetic constant by a factor of 500 [4]. The adjusted parameter accounts for mass and heat transfer limitations in the flowloops. The current model assumes that the hydrate particles convert directly from emulsified water droplets. Nucleation is assumed to occur instantaneously at a subcooling of 6.5°F, a parameter proposed by Matthews [5]. Once formed, the model assumes that these particles remain in the oil phase. The change in relative viscosity of this phase is then found from the Camargo and Palermo [6] correlation for steady state slurry flow. An overview of the current CSMHyK module and its integration into OLGA is shown in Figure 1.
Installation-Driven Field Developments for Deepwater Subsea Projects
Authors: Dixon Mark A.J. , David Easter
Published: October 2008

At the concept select stage and certainly at the FEED stage of deepwater subsea projects the focus is often exclusively on optimisation of functionality during operation. For deepwater and particularly in the current market climate, however, the ‘best’ field development may need to satisfy other drivers. The ‘best’ solution does require knowledge and definition of what is considered of most value to the project whilst managing CAPEX and lowering risk.

Given that, for a Greenfield subsea development, approximately one third of the CAPEX is associated with the SURF (subsea umbilicals, risers and flowlines) package, and around one half of this cost is attributable to the offshore installation phase. Along with all the risk, there are strong commercial reasons alone for focusing on installability during all phases of the development cycle. Layering on top of this the shortage of capable vessels and their tight availability, the development scenario that provides a greater number of suitable vessels for offshore construction offers a more competitive bid phase, additional schedule benefits and lower risk as the subsea systems are that much more installable by design.

This paper illustrates how an installation-driven (or installation-focused) development process provides the necessary operational functionality for deepwater subsea projects by leveraging recent experience on a variety of projects from around the world.

1.0 INTRODUCTION

In a world of ever-increasing demand for hydrocarbons, the race is to tap the deepwater resources and get the production started as early as possible. For a deepwater subsea field development this leads to a fast-track approach and due attention is not given to all project drivers. At the concept select stage and certainly at the FEED stage of deepwater subsea projects the focus is often exclusively on optimisation of functionality during operation. For deepwater and particularly in the current market climate, however, the ‘best’ field development may need to satisfy other drivers. The ‘best’ solution does require knowledge and definition of what is considered of most value to the project whilst managing CAPEX and lowering risk.