bluuebunny/crossref_metadata_2025 huggingface dataset:
Carbon Fiber Composite Tendons for Deepwater Tension Leg Platforms
Authors: Sparks C. , Zivanovic I. , Sparks Freyssinet , Luyckx J. , Sparks Soficar , Hudson W.
Published: October 2008

The paper presents new technology for the tendons of deepwater Tension Leg Platforms (TLPs) based on Carbon Fiber Composites. The technology, named 3C-TendonsTM, has been developed by the group comprising Freyssinet, Soficar, Bostik Findley, Institut Français du Pétrole and Doris Engineering. The technology solves the problems of weight and fatigue which become critical for TLPs in very deep water. The tendons are made up of multiple numbers of subelements each of which comprises 19 rods, all of which are spoolable for transport. For the complete tendon, the partners have opted for parallel rods and sub-elements for technical reasons explained in the paper. Final installation is by the method of tow-out and upending.

Introduction - Background to TLP tendons

When designing the tendons of a TLP the designer has the triple technical objective of ensuring that:maximum loads at the tendon top ends do not exceed acceptable values;cumulative fatigue damage due to fluctuating axial stresses is acceptable;bottom end effective tension remains positive at all times and hence that tendon buckling is avoided. Tendon pretension in particular has to be chosen to avoid such buckling.

Tendon pretension

Tendon pretension can be considered as part of the total load on the platform. There is therefore considerable motivation to reduce its value as far as possible. This involves firstly minimising the apparent weight in water of the tendons.

All TLPs constructed to date are anchored by steel tendons which, in virtually all cases, have been composed of hollow tubes. These have been left air filled at atmospheric pressure to reduce their weight in water. The tendons of the Jolliet TLP (528m depth) were almost neutrally buoyant with a D/t ratio of 30. For subsequent TLPs in water depths down to 1200m lower values of D/t (20-25) have had to be used because of the combined effect of external pressure and axial loads.

As water depth increases towards the ultra-deep the D/t ratio has to be even further reduced to prevent collapse from external pressure. This leads to heavy tendons if the crosssection is maintained constant and hence requires a significant increase in displacement of the TLP to support the additional load. An alternative is to use "stepped tendons" for which the diameter is increased in steps towards the upper end. This is equivalent to incorporating buoyancy in the upper part of the tendon itself.

The other alternative is to fabricate the tendons from a different, naturally lightweight material, such as carbon fiber composite. The weight of such composite (specific gravity 1.59) is only slightly greater than that of water. Hence carbon composite tendons do not require buoyancy to be incorporated in the tendon to reduce their weight in water. Furthermore they are capable of resisting external water pressure without collapse and their resistance to static and fatigue loads is significantly better than steel.
Model Test Experience on Vortex Induced Vibrations of Truss Spars
Authors: van Dijk Radboud , Magee Allan , van Perryman Steve , van Gebara Joe
Published: October 2008

In order to evaluate the Vortex Induced Vibration (VIV) response of truss Spars and to optimize their strake configuration several model test programs have been carried out at MARIN. The results show that it is possible to optimize the strake design of Spars to obtain minimum VIV-response. The results of the model tests also suggest that modeling details, such as appendages, can have an influence on the Vortex Induced Vibrations. In order to reliably predict the full-scale VIV-behavior of the prototype Spar these details must therefore be accurately represented on the model. Furthermore, damping of attached structures such as the truss on a truss Spar can significantly contribute to the reduction of VIV. Loads on such structures have been measured in the model tests.

An important aspect that needs consideration in VIV model testing is effect of model scale on the Reynolds number. Roughness can be added to the hard tank of the Spar to minimize scale effects. The paper discusses possible scale effects and the effect of hull roughness on model test results. The repeatability of VIV model tests and reliability of these tests in representing the full-scale situation is discussed. The effect of Spar heading with respect to the current direction as well as current speed will be discussed.

Introduction

Since 1996 Spars have been used as production platforms in the Gulf of Mexico. Vortex Induced Vibrations (VIV) of the Spar are an important consideration in mooring system design. The Vortex Induced Vibrations of Spars are typically reduced by adding helical strakes to the Spar hull. The effectiveness of the strakes must be verified in the design stage of the Spar. At present numerical tools are not capable of accurately predicting VIV-behavior of Spars. Model tests are therefore currently the most practical method to verify and optimize the strake design.

A new development in Spar design is the so-called truss-Spar (Refs 1 & 2). In order to evaluate the VIV-behavior of this type of Spars dedicated model tests have been conducted on several truss Spars.

Vortex Induced Vibrations

A blunt structure placed in a flow (either air or water) will experience an oscillating force due to the shedding of vortices. This phenomenon is studied and discussed extensively (e.g. Ref. 3). If this structure is able to move in the flow Vortex Induced Vibrations (VIV) can occur. The predominant direction of these motions is transverse to the direction of the flow. Large steady state type oscillations occur when the vortex shedding frequency coincides with a natural frequency of the structure. This is known as 'lock-in'. For offshore structures these vortex induced vibrations could add to the fatigue damage of mooring and risers, shortening the total fatigue life and also increase the overall drag on the structure. Experience has shown that in offshore structures cylindrical objects such as risers, calm buoys and Spars are most susceptible to VIV, but also other shapes can exhibit VIV-behavior.
Seabed Located Drilling Rig - ITF Pioneer Project
Authors: Ayling L.J. , Jenner J.W. , Neffgen J.M.
Published: October 2008

ITF Pioneer Project PX 1017 is the Feasibility Study of a drilling rig that is located on the sea bed. The new Seabed Drilling Rig (SDR) and its Rig Support Vessel (RSV) are simpler and considerably less expensive than previous attempts to re-locate a land rig subsea. (See CAD Illustration.)There are no rigid risers between SDR and RSV.The SDR is largely insensitive to weather and the RSV has a far larger envelope in which to operate.The SDR is modular and can be deployed through a normal moon pool in the RSVThe SDR uses standard drilling procedures and jointed tubulars;The main control of mud circulation, to and from the well, is at the seabed.This SDR technology leapfrogs current 'riserless drilling' technology, but applies many useful lessons learned.The projected costs, per well drilled, compare favorably with floating drilling in as little as 1,000ft (300m) of water and do not increase significantly with water depth.Reductions in current well construction costs of up to 30% appear feasible in 3,500ft (1,100m) water depth.Reductions in current well construction costs in excess of 30% appear feasible in 7,500ft (2,300m) water depth.Locating the Rig on the seabed apparently offers the best technical and economic solution for drilling in 10,000ft (3,000m) water depth and, because of its low depth sensitivity, the technology can be extended to 20,000ft (6,000m.) water depth. The step change in economics is due to a new method of handling all tubulars & tubular assemblies, plus a new mud control system combined with the Continuous Circulation System (presented in OTC Paper 14269 in 2002).

Results, so far, indicate that there are no apparent show stoppers. Detail Design is planned for 2003/2004 with a prototype operating in 2006.

Introduction

In conventional offshore drilling, the drilling rig is located above the water surface; on the deck of a 'bottom supported'installation such as a submersible, jack-up, or fixed platform, or on the deck of a 'floating unit', such as a semi submersible, or drill ship.

Drilling from 'bottom supported' installations provides similar conditions to drilling on land. 'Floaters' have to contend with the relative motion between the drilling unit and seabed by tensioning the riser, with its telescopic joint and flexible hoses at the surface and flex or ball joint above the sub-sea BOP stack. The drill string must also be maintained in a constant position in the hole by the use of a heave compensator in the derrick.

The equipment necessary to handle the marine riser, drill string and casing becomes exponentially heavier and more costly with increasing water depth, to the extent that semis and drillships, capable of drilling in up to 10,000ft (3,000m) of water, now cost of the order of ﹩350 million to ﹩500 million to build.
Installation of metallic tube umbilicals in 3,000 meters water
Authors: Dieumegard C. , Fellows P.
Published: October 2008

This paper discusses the design and the installation of steel tube umbilicals for service in 3000 metres water depth. Designs of functional components and umbilical cross sections to cope with the specific requirements of the ultra deep water are reviewed in terms of availability and qualification status. Current installation practice is then reviewed and its inherent limitations are outlined - Limitations which may well be reached sooner rather than later. This paper proposes some means by which these limits can be increased.

Introduction

This paper discusses the development of steel tube umbilicals for service in 3000 metres. Design and qualification status of functional components and umbilical cross section arrangement are reviewed. Areas where further developments are needed are identified, and solutions are proposed to cope with the specific requirements of the ultra deep water.

In a second part, limitations of the current installation practice; conventional 'overboarding' using installation chutes are outlined. Limitations on installation depth achievable with current installation constraints, in terms of tensioner track length and chute radius, are examined.

This paper proposes some means by which these limits can be increased. Predictive modelling of the radial stiffness of umbilical bundles is reviewed and practical methods of increasing radial stiffness, to permit higher values of clamping pressure within the tensioner, are outlined.

Umbilical Design for 3,000 meters water depth

Metallic tube. Tube wall thicknesses are determined according to the ISO-13628-5 standard (which takes into account hoop and radial stress, end cap effect and tensile load). The Collapse resistance (vs. buckle propagation) of the tube is checked according to well-recognised standards such as API 1111 or BS 8010.

Metallic tubes have an intrinsic high resistance to collapse. Therefore in shallow water the governing factor for the determination of the tube wall thickness is the combined effect of pressure and axial tension. However for deep and ultra deep water the collapse resistance (based on the buckle propagation pressure) can be the main factor for the design of the tube wall thickness. It is therefore critical for the umbilical designer to know the exact function of each tube, the characteristics of the conveyed fluid, and the possibility for a tube to be empty, or filled with gas.

Figure 1 presents the tube wall thickness calculated as per ISO-13628-5 standard for several types of tube (from 1" to 2" ID, all 5ksi DWP - SMYS = 620MPa) designed for dynamic application in several water depths (from 500m to 3,000m) and considering the tube designed to be collapse resistant or not.
Subsea Tree Installation, Lessons Learned on a West Africa Development
Authors: Voss Robert , Moore Tony
Published: October 2008

A Subsea Production Development Project was undertaken in West Africa. The Development is a subsea production project in 1200 ft of water. Twenty-eight subsea Horizontal Trees (HT) were installed from 1999 through 2002 in four drill centers over several campaigns. A remaining five trees are scheduled for future installation.

A project was undertaken to review and analyze the field service reports for each of these installations. The scope of this review included the subsea tree, tubing hanger, crown plug, internal tree cap, and debris cap. Ancillary operations such as wear bushing retrieval, bop test tool, straddle sleeve, and bore protector were also included. Other subsea equipment and interfaces were not subject to this analysis in order to maintain focus on the tree itself.

The review of this data had several purposes:To compare the equipment and activity performances against related variables such as rig, personnel, well condition, and environmental conditions.For benchmarking, to establish mean and standard deviations of installation times and other key variable data such as landing loads, pull-out forces, etc.A critical review of the installation procedures against the actual field reports to look for "hidden factories" and other undocumented activities. Based on this review, the procedures were revised to both optimize the process, and ensure the required performance data is recorded.To establish a standard electronic format for the future collection of field tree installation data. This on-line database will be used to maintain baseline performance statistics, identify equipment performance trends, and formally address field failures for complete resolution. The field data will be back-loaded into this existing WELS (Well Electronic Log System) database, and all future tree installations will use this format. This paper will document the results of the West Africa installation data analysis, including:Presenting the installation data in chart and graph format.Drawing conclusions about the equipment performance and effectiveness of the procedures.Making recommendations as to the requirements for a tree installation data collection system.

Introduction

Project and Field Description

The field, discovered May 1997, is located in West Africa in about 1200 ft of water. The operator for and on behalf of joint venture partners decided to develop the first of three phases as a fast-track early production system. First oil was in December 1999, 30 months after discovery and 15 months after contract awards.

Refer to Figure 1 for an illustration of the full field development.

The field is a full subsea development with a local FPSO host. The nature of the field dictated multiple drill centers and pressure maintenance on the natural drive reservoirs. The subsea architecture is a traditional cluster system with discrete wells surrounding central manifolds at each of the three major drill centers. Another key aspect of this development was the desire to maintain a Zero-flare environment for the produced gas.
Cryogenic Flexible for Offshore LNG Transfer
Authors: Cox P.J.C. , Gerez J.-M. , Biaggi J.-P.
Published: October 2008

This paper addresses the conception, development and testing of a cryogenic flexible, and its integration and qualification as part of an overall offshore transfer system. This technological advance has been made possible by Joint Industry Projects (J.I.P.), sponsored by both major Oil & Gas companies, and shipping & service companies. Development is ongoing and an industry Specification is one of the main aims.

Introduction

The industry trend towards the offshore production and transfer of LNG has lead to the requirement for innovative solutions to ensure safety in a marine environment and acceptable operating envelopes between the production units and the shuttle tankers. One solution is the use of a cryogenic flexible as part of an integrated transfer system, for both loading and offloading. The main part of this paper is dedicated to the cryogenic flexible itself, whilst a short second part discusses the system approach.

1.0 Cryogenic Flexible

1.1 Design Basis The characteristics of Liquefied Natural Gas, in particular its temperature of -163°C and the large volumes involved, means that the traditional methods and materials used for the manufacturing of flexibles for offshore use in the Oil and Gas Industry are not acceptable, and that alternative techniques must be used.

At the initial stage of its development, no industry standard existed, however in order for one of the recognised Certification authorities to have a basis upon which to eventually propose such a standard, reference was made to the following:Oil Companies International Marine Forum (OCIMF) "Guide to Purchasing Manufacturing and Testing of Loading and Discharge Hoses for Offshore Moorings", 1991 (OCIMF 91)British Standards (BS), "Specifications for Hose and Hose Assemblies for Liquefied Petroleum Gas", BS 4089, 1989.British Standards (BS), "Flexible Metallic Hose Assemblies", BS 6501, 1991Expansion Joint Manufacturers AssociationCode des Appareils et Pression These parameters cover both the loading and gas return conditions.

The prototype design, whilst being a 16- full bore flexible, allows full extrapolation of all results up to an internal diameter of 24-.

The minimum service life is set at 5 years with a safety factor of 10 relative to fatigue life. Where possible, materials with a proven track record within cryogenic applications were chosen.
A Study on Suction and Scouring of Sit-On-Bottom Type Offshore Structure
Authors: Ninomiya Katsuya , Tagaya Kozo , Murase Yoshihide
Published: October 2008

The authors made reports on the study of the same subject at Offshore Technology Conference held in 1971 1). The conclusions that were announced at the Conference are as follows:As to the suction under freeing-on-bottom of the sit-on-bottom type offshore structure which settles on the sea bed soft cohesive soil:An effective shape of the bottom of the structure against suction is n.The suction mechanism became clear to obtain' practical formulas of the suction force when the suction breaker was not used.As to the scouring by the waves or the tidal current when the sit-on-bottom type offshore structure settles on the sandy soil:A skirted hemispheric leg is most effective against scouring.The characteristics of scouring by the waves or the tidal current became clear. But in the above reports it Was noted that the following problems still remained unsolved:

But in the above reports it was noted that the following problems still remained unsolved:As to Suction: In the formula for obtaining the suction force there are still some unobvious elements.As to Scouring: The method to assume the scouring on the prototype has not been studied yet. The authors made more detailed studies to solve these problems, and have obtained the following conclusions:

The authors made more detailed studies to solve these problems, and have obtained the following conclusions:As to Suction: The suction force consists of the side friction, the viscous force and the bottom adhesion, and the Cogitative calculation became possible of each of these forces.Side Friction: The important factor is the time that the offshore structure is left on the sea bottom after settling, and the relation between the side friction and the settling-time of the structure Was obtained.Viscous Force: The important factors are the width or the diameter of the bottom settling on the sea bed F the pulling velocity and 'the viscosity of soil; and the relation between these three factors and the viscous force Was obtained.Bottom Adhesion Force: The bottom adhesion force depends on the cohesion of soil and the settling-time of the structure, and the relation between these two was obtained.
Wash Pipe Or No Wash Pipe? That is The Question
Authors: Pineda Francisco , Traweek Bryce , Curtis James
Published: October 2008

Conventional gravel pack or frac pack completions typically require the use of wash pipe to act as a conduit for fluid returns as well to carry a shifting mechanism to open or close a return port. Using properly sized wash pipe can enhance the placement of the gravel across the entire annular space and the formation. It can be used in conjunction with a shifting mechanism and a sliding sleeve to force the fluid returns to pass through the bottom of the screen. It can allow a washdown capability while running the assembly into hole. In specialty systems, it can even act as a pumping conduit for post-gravel pack stimulation.

However, the use of wash pipe, especially in long horizontal wells, means the loss of valuable rig time due to make up and break up of the wash pipe, or recovery if the wash pipe is stuck. Economic considerations, along with completion efficiencies, are especially important on deepwater completions. Not using wash pipe reduces rig time, generating significant cost savings, and also eliminates the risk of sticking it.

This paper reviews conventional wash pipe applications and describes new systems that accomplish the same goal with a minimum amount of wash pipe or no wash pipe at all.

Uses of Wash Pipe

The production of formation sand into a well is one of the oldest problems plaguing the oil and gas industry because its adverse effects on well productivity and equipment.1

Gravel packing and frac packing are the methods of choice for sand control. In combination with sand screens they provide downhole filters to prevent production of formation sand. During the execution of these methods, a properly sized sand or proppant has to be placed in the formation as well as the annulus of the screen-casing or screen-open hole using a gravel pack packer assembly with a gravel pack service tool and wash pipe inside the sand screen, with its bottom hanging as close as possible to the end of the screen. This configuration aids the placement of the sand or proppant by allowing the gravel pack fluids to travel down the tubing, through and out the ports of the gravel pack service tool and assembly, down the blank/screen-casing or open hole annulus, into the perforations or open hole, through the screen, up the wash pipe and gravel pack service tool, and into the gravel pack packer-casing annulus.

Wash pipe can also be use as a conduit to allow washdown capabilities when installing screens or liners. In isolation systems, wash pipe is used to run shifting tools to activate sliding sleeves in order to achieve returns during gravel packing.

There are also other economic factors to consider when using wash pipe, such as the valuable rig time necessary for making up, running in and breaking up, especially in horizontal wells, and also in the unfortunate case of fishing if the wash pipe becomes stuck.

Wash Pipe Selection Criteria

Proper selection criteria include strength, material, connection type, and diameter.
Monitoring of Sand Deposition in Subsea Separators
Authors: Eriksson Klas Goran , Kirkedam Eivind
Published: October 2008

Subsea processing systems for e.g. water removal and reinjection have been in operation for some time, and are being studied for use in several fields.

In many applications, sand handling is a problem. The sand may accumulate in the separator vessel, and needs to be flushed out at regular intervals. As the sand may accumulate anywhere in the vessel, a wide-area sensing system is required in order to detect sand deposits anywhere in the vessel. The SPC (Subsea Processing Collaboration) project has studied such systems, and selected and lab tested two such systems based on thermal methods. A 1 ft wide, 1" high sand heap can be detected anywhere in the vessel. One system is based on measuring the outside temperature of the separator vessel (inside the insulation). Solids inside will cause the outside to cool, which is readily detectable by Pt100 or fibre optic temperature sensors. Another system is based on internal rods located 1" above the separator floor. These contain "hot spots", to which electric power is fed. The temperature increase depends on whether the "hot spot" is surrounded by water or sand. This paper summarizes the work done by the SPC consortium over the last 3 years, discusses a typical process to highlight the performance requirements, describes the work done on the two types of systems selected, and presents the results of lab testing and simulation done to date. Alternate systems are also discussed.

Introduction

Subsea processing systems for e.g. water removal and reinjection have been in operation for some time, and are being studied for use in several fields.

In many applications, sand handling is a problem. The sand may accumulate in the separator vessel, and needs to be flushed out at regular intervals. As the sand may accumulate anywhere in the vessel, a wide-area sensing system is required in order to detect sand deposits anywhere in the vessel. The SPC project (a collaborative effort between BP, ChevronTexaco, ABB and AkerKvaerner) has studied such systems, and selected two such systems based on thermal methods.

A typical subsea separation process

A subsea separation process typically involves one or several gravity separator vessels, possibly combined with cyclones. A sketch of such a system is found below in fig I below.

Figure I Typical Separation Process (Available in full paper)

The gravity based separator vessel we are discussing is highlighted in the figure. It may be fairly large, e.g. 2.5 × 10 meters (D × L) (10 × 30 ft D × L), and have a volume of 50 - 100 m3. The dry weight can be 50 - 100 tons.

The consequences of sand deposits

As sand deposits in the separator, the volume available for fluid decreases correspondingly. If the separator is e.g. filled to 50% with sand, then the effective volume available for fluid separation has decreased to 50% (i.e. the residence time has been halved). The operator would then need to decrease fluid flow to half in order to maintain the residence time. The sand accumulation may thus necessitate a production reduction.
Offshore Salt Caverns Enable a 'Mega' Sized LNG Receiving Terminal
Authors: McCall M. , Davis J.F. , Krekel M.H.
Published: October 2008

The unique and heretofore unknown combination of gas storage in man made salt caverns with LNG importation presents the possibility for LNG receiving terminals with very large storage capacity and gas send out flow rate. In particular, the use of salt formations for cavern development and LNG receiving in the Gulf of Mexico has the potential for offshore facilities combining easy ship access, large storage, and very large send out to the gas pipeline grid. This paper describes such a facility, its components, capabilities, and operating characteristics as well as an overview of some of the design decisions made as the Basis of Design takes form. This offshore facility will be further described in greater detail as a part of a U.S. Department of Energy (DOE) cooperative research project commissioned by the National Energy Technology Laboratory (NETL) and having cost sharing participants from a wide array of energy industry companies.

Introduction

LNG has been a very small part of the U.S. natural gas supply over the last thirty years. Some forecasts project that LNG imports could make up as much as fifteen percent (15%) of future natural gas supplies to the United States. This means that the capability to receive natural gas in the form of LNG, process that gas if necessary and distribute that gas to a gas hungry nation will require a significant increase in capacities throughout the delivery system. Further complicating the large increase in LNG import expectations is the fact that all LNG is not equal. Depending upon the country of origin and the specific liquefaction plant, the LNG produced can have significant variation in composition. Some plants produce LNG at a little over a thousand Btu/scf others far exceed eleven hundred Btu/scf. All LNG is clean and dry, with low sulfur and low CO2, but the variation in gas liquid content provides an opportunity and a challenge for the gas processing industry.

Table for Source, Lean and Rich (Available in full paper)

There are more than forty LNG receiving terminals in the world. They are the same basic design, differing mostly in size. They consist of a dock to moor an LNG ship, cryogenic loading arms for the product transfer, cryogenic liquid storage tanks, LNG pumps capable of achieving pipeline pressures, and some form of heat exchangers or vaporizers to warm the LNG to pipeline compatible temperatures as it leaves the facility. This basic design has not changed since its introduction in Japan where more than half of the worlds LNG terminals exist, see fig. 1 for a tank based process. Significant scale increases have been introduced into the world's LNG business in liquefaction and shipping. Offshore salt cavern based terminals can provide the corresponding scale increases needed in LNG receiving terminals with storage capacity and send-out volumes far exceeding the tank based terminal model.
Floating LNG Production Facility
Authors: Lund Trygve Johannes , Wichstrøm Finn , Pepperell Ray , Sparby Bjørn
Published: October 2008

Objective

The objective of the study was to prove the feasibility of a floating LNG (FLNG) production facility for the NnwaDoro gas field, to provide solutions for identified problems and to demonstrate that all FLNG related requirements could be met.

This paper will mainly focus on the safety and layout aspects of the study, but includes also the other parts of the work performed by Aker Kvaerner

Process

The study was based on the Linde MFC ® (Mixed Fluid Cascade) LNG Process for the production of 5.8 MTPA LNG plus propane, butanes and condensate in a single process train. The study was performed by Linde and Aker Kværner as subcontractor on behalf of the MOU Team; Statoil, Shell and NNPC.

HSE

For the NnwaDoro FLNG barge the aspects of gas dispersion and gas explosion was considered as key elements when assessing the governing key parameters for the barge layout. The only established type of method to determine dimensioning explosion loads and gas release type and rate is to perform a proper Risk Analysis, calculating both the probability of accidents to occur and the associated consequences. For a Concept Study this is traditionally performed on a coarse level, however, using all the available information in the project at that time. For the NnwaDoro Study the relevant information available was the Process Flow Diagrams, the 3D model, wind data plus the process calculations. In addition to this generally available information was used. A relevant methodology to be used for a Risk Analysis is NORSOK Z-013.

All explosion and dispersion calculations done within this study was sample calculations. It is important not to misinterpret the safety work carried out under this contract as a substitute for a coarse Risk Analysis. However, the gas cloud sizes and ignition points as well as release rates were chosen in order to be conservative. It was our objective to produce a NnwaDoro FLNG design which was robust and able to absorb natural design development during the coming phases without overturning the basic layout. However, the accidental effects calculated were anticipated to be well within the realistic range. In the course of this study the major FLNG related safety issues have been identified, i. e.:Explosion loads within modules and its impact on other SystemsImpact of explosion loads on carrier during side by side LoadingA safety philosophy for the FLNG facility was establishedDispersion studies was performed and the dispersion of gas jet and general ventilation in the process modules was found to be within acceptable limits
SEDCO - 445 Dynamic Stationed Drill ship
Authors: Hammett Dillard S.
Published: October 2008

This paper deals with the design parameters, fabrication and sea trials of the first ship equipped for dynamic stationing having the specific requirements for drilling exploratory wells in open ocean environment.

Design criteria are reviewed with regard to sea state, environment, propulsion requirements and drilling performance, including automatic control and sensing systems. Model studies and dynamic simulation analyses are presented and compared with the results of early sea trials. Operating systems are summarized, and performance expectations are related to prospective utilization of the vessel in specific ocean areas. Preliminary conclusions are given with respect to vessel response to control and propulsion parameters.

Introduction

The trend in offshore exploration clearly indicates that the Oil Industry must extend its search for oil and gas into water depths beyond the continental shelf. The need for additional oil and gas reserves; and the belief that sizable reserves could indeed exist in greater water depths have encouraged interest in deepwater exploration. This deepwater exploration has resulted in the need for new techniques and tools for water depths of 2,000 feet and greater.

Royal Dutch/Shell Group, with their established world-wide interest in offshore exploration and production and their technological achievements in the offshore environment, has taken a natural step to undertake early development of drilling techniques and tools to explore in the deeper waters.

Extensive study of exploration objectives and research into the means of achieving these culminated in Royal Dutch/Shell engineers drawing up comprehensive engineering specifications for a highly mobile drill ship. Early in 1970, the drilling contractor, SEDCO, Inc., was engaged to design, construct and operate the drilling unit, now known as the "SEDCO 445." At the same time, Royal Dutch/Shell and SEDCO engineers undertook detailed final development of advanced forms of dynamic stationing and underwater drilling equipment. The major limiting factors to existing offshore exploration drilling are the anchoring capability and the underwater drilling equipment system.

A specially designed ship equipped with dynamic stationing has the capability of anchoring in unlimited water depths. The use of new techniques such as Electro-Hydraulic BOP controls; acoustical re-entry; and riser buoyancy increase the capability of the underwater drilling equipment system to something greater than 3,000 feet.
An Overview of More than One-Hundred-Twenty Horizontal Gravel Packing Operations In Campos Basin
Authors: Marques L.C.C. , Calderon A. , Chagas C.M. , Fernandes L.H.C. , Pedroso C.A. , Neumann L.F. , Rocha J.D.H. , Paixão L.C.A. , Barbosa V.P. , Pereira A.Z.I.
Published: October 2008

This paper presents the lessons learned by Petrobras after performing a total of 124 horizontal open hole gravel-packing operations in Campos Basin. The authors intend to describe how the industry-provided standard gravel packing procedures had to be continuously improved and/or adapted to meet Campos basin requirements, such as: -low fracture gradients, - long intervals to be packed, -pumping jobs performed from floating rigs and -the need to sustain high production levels - or high injection rates - to justify the huge amount of investments associated to ultra-deepwater production enterprises. It is also described the main technology innovations that were incorporated to our completion projects in the last few years. Among these innovations one can find: - modified standard tools to reduce pumping pressures, - external casing packers, -inflatable straddle packer to divert post-gravel treatments, -pressure reducer valves, - - flowline's flow meter and shunt tubes. Formation damage in gravel packing operations is addressed on a comprehensive basis, encompassing the following items: -drill-in fluid rheological specifications, - pre-job wellbore cleanup procedures, - optimizing drill-in-fluids mud cake removal, -job design and execution, gravel carrier fluids filtration requirements, -postjob remedial treatments and diversion techniques as well.

Introduction

The most prolific reservoirs in Campos Basin are Tertiary and upper Cretaceous unconsolidated turbidites that require a sand control/exclusion method either to maximize sand-free production or to manage massive water injection to provide reservoir pressure maintenance. Therefore, from the firstdiscovered oifields in shallow waters to the large ones more recently discovered in deep- and ultra-deepwaters scenarios in Campos Basin, emphasis has been placed on total sand exclusion well completion techniques.
Prediction of Spar Responses: Model Tests vs. Analysis
Authors: Steen A. , Kim M.H. , Irani M.
Published: October 2008

The DeepStar Program has sponsored a series of tasks to evaluate the current industry capability in predicting the responses of deepwater theme structures (FPSO, TLP and SPAR). In its Phase IV program, model tests of the FPSO, TLP and SPAR were conducted, and in the Phase V program, engineering companies as well as test basins were invited to evaluate the correlations between the tests and analyses.

This paper presents an overview of DeepStar's effort with emphasis on Spar responses. It covers the following areas of response predictions:Model test setup and test conditionsThe state-of-art analytical tools available to the industryEvaluation approachKey results of comparisons - tests vs. analysesSensitivities and uncertainties in predicting Spar responsesAssessment of current industry capabilitiesAreas of future effort

Introduction

Model tests were conducted November 2000 in the new offshore basin of the Maritime Research Institute Netherlands (MARIN). The objective of the tests was to assess global responses of floaters, with emphasis on the effect of mooring line and riser dynamics in deeper water. These tests included a TLP, Spar and FPSO.

During the early part of last year, industry participants of the DeepStar Program were contracted by Det Norske Veritas (DNV) to analytically model the tests using their in-house programs. This paper presents results of that effort for the spar platform conducted by the authors. Modeling particulars and applied computer programs are presented. Test results and predictions are tabulated and shown graphically. Overall, there is good to excellent agreement between predictions and test measurements.

Model Tests

A brief description of the applied test facility, model and test particulars are given herein. Details may be found in references 1 and 2.

Test Facility

The MARIN deepwater test basin is 10.5m deep and 45m × 36m in cross section. Multi-flap wave generators on two sides can produce long-crested or short crested waves up to 0.4m with periods of 0.3 to 3.0 seconds, model scale. Current can be generated over the full basin depth with a vertical profile. Wind spectra are produced with electrical fans on a free moving and position-controlled platform.

Spar Model

Spar tests were conducted with length scale factor 1:87. This simulated a water depth of 913.5m. The spar model was a "classic" spar which is a vertical steel cylinder supporting topside facilities and a centerwell for top tensioned risers. The full-scale hull depth was 214.9m with a 198.1m draft and 37.2m diameter. The deck length, width and height were 65m, 65m, and 27.1m, respectively, with a vertical cg 241.7m above the spar keel. Mass properties, including adjustments to KG and GM for entrained centerwell water are given in Table 1. A sketch of the spar with mooring and risers is given in Figure 1.

Table 1 Spar Mass Properties (Available in full paper)
Subsea System Design for the HPHT Kristin Field Development. Thermal and Pressure Loads.
Authors: Hundseid Jan , Flaten Gunnar
Published: October 2008

The HPHT field Kristin is located 16 km south west of the Åsgard field in the North Sea. The reservo ir has a temperature of 170°C and a pressure of 911 barg. The field will be produced by pressure depletion from four subsea templates tied back to a dedicated floater. Kristin is the first subsea HPHT field development. First production will be autumn 2005.

The production lines, flexible risers and the topside process are protected by three separate pressure protection systems including a subsea HIPPS system. Direct electrical heating will be installed for the production line as the main hydrate control measure. For the design of the subsea system and the operational procedures for the system, special attention must be given to the high temperature and pressure. The high and low temperatures imposed on the production system by the producing fluid during normal production, shutins, restarts and operational/system failures make the design challenging.

This paper will give an overview of the flow assurance work. The design and operational consequences of the high pressure and temperature loads on the wells, templatepiping, production lines, electrical cable and flexible riser are presented.

Introduction

The Kristin field is located offshore approximately 160 km from the Norwegian coast in the Haltenbanken area. It is a gas/condensate field with estimated recoverable reserves of 42 billion Sm3 of gas and 35 million Sm3 of condensate. The gas will be exported through the 700 km Åsgard pipeline to Kårstø for onshore processing. The condensate will be sent to Åsgard C for storage and offloading. Production start -up is planned October the 15th 2005.

Figure 1 Kristin field (Available in full paper)

Figure 2: Kristin field location (Available in full paper)

The Kristin field is a high pressure and high temperature (HPHT) field2. The producing formations Garn and Ile are located 4500 m and 4850 m below the seabed. The Ile formation has the highest reservoir temperature and pressure of 169°C and 911 bar. The Garn formation has a temperature and pressure of 164°C and 894 bar respectively. The field will be produced by pressure depletion.

The Kristin field is the first HPHT field to be developed subsea. There will be 12 subsea wells and four templates (see Figure 3). There will be four wells at template R and S and two wells at template P and N. Six 10" ID flowlines will transport the produced fluid to the Kristin semi; two flowlines each from template R & S and one flowline each from template P &N. The flowline lengths vary between 6 and 6.8 km. Flexible risers with a length of approximately 700 m connect the flowlines to the process facility on the semi. The water depth on the field varies between 315 and 375 m. The design rate for the flowlines is 4 MSm3/d of gas. Depending on the flexible riser arrival temperature, the production can be increased to 5 MSm3/d. The receiving facility is a semi submergible roduction unit.
Hydrodynamic Aspects Of Gravity Based Structures In Shallow Water
Authors: Buchner B. , Loots G.E. , Forristall G.Z. , van Iperen E.J.
Published: October 2008

The concrete Gravity Based Structure (GBS) is an attractive concept for shallow water oil and gas developments. The present paper discusses 3 subjects related to the concept:Wave amplification by the large elements of a GBS causes significant problems in setting deck elevations. Physical model tests have usually been required for accurate results. Linear diffraction theory combined with second order simulations of crests heights gives predictions of crest heights with useful accuracy. The simulations tend to be somewhat conservative since they ignore the effects of wave breaking.The hydrodynamics of LNG carriers moored to GBS type structures are complex: this relates to the multi-body interaction in the wave forces, added mass and damping, but also to the drift forces in shallow water. With an optimum orientation of the GBS, a shielding can be achieved for the moored LNG carrier, reducing the weather downtime. However, a wave field still exists behind the GBS due to diffraction, which depends on the wave direction and wave period. For some motions (such as roll) there is very little shielding.A GBS used as an LNG terminal will be oriented to shelter the carriers from the dominant sea direction. The survival conditions will often be beam to the GBS as well. This means that the wave run up and possible green water on the deck of the GBS is a problem that needs serious evaluation. With the improved Volume Of Fluid (iVOF) method it is possible to simulate the run up again the side of a GBS.

INTRODUCTION

A concrete Gravity Based Structure (GBS) for offshore oil production usually consists of a base caisson supporting several vertical columns which in turn support a deck containing productions facilities. A GBS has many advantages when used in the proper situations. Some of the first were built for deep water fields in the Norwegian sector of the North Sea. The Troll platform in 303 m water depth remains the tallest object ever moved over the face of the earth. The Norwegian fjords provided a perfect and almost unique location for the construction of these platforms. Their deep, sheltered waters allowed for slip-forming the columns as they were gradually ballasted lower in the water. Soils in the Norwegian sector were strong enough to support the massive structures and their mass is sufficient to resist the overturning forces caused by environmental loads.

Since the base of a GBS is large, it is easy to adapt it for oil storage. Production can then be stored until a load large enough to fill a tanker is accumulated. This method of transportation can be the most cost effective solution in remote areas far away from existing pipelines.

Figure 1 Gravity Based Structure as LNG import terminal (Available in full paper)

Malampaya is a good example of the advantages of a GBS in shallow water (Chudacek et al., 2002 [1]). The Malampaya gas field is actually in water about 820 m deep, but the production is sent from the subsea wells by pipeline to the GBS in 43 m depth where it is processed.