bluuebunny/crossref_metadata_2025_split huggingface dataset:
LNG FPSO Based on Spherical Tanks
Authors: Wadahl Anders , Christiansen Per 
Published: October 2008

Abstract
During the last years, the interest in LNG FPSO's has been revived. One of the challenges in designing a LNG FPSO is the liquid sloshing in partial filled tanks. One of the unique features of the spherical tank is that it is certified for operation with part filling to any level. It is therefore well suited as containment system for floating LNG production units.
The spherical tank was developed as a containment system for LNG carriers more than 30 years ago. The tank is essentially a shell supported by a cylindrical skirt through a patented transition joint. The spherical shape results in membrane type operational stresses and bending moments are limited to the transition area where they are carefully controlled. The tanks are today constructed entirely of aluminum by specialized shipyards around the world. The spherical LNG tank is installed in close to 70 LNG carriers, some of which are nearly 30 years old and have recently been certified for another 20 years service. All vessels built are still in service today and no serious incidents directly attributed to the tank construction have ever been reported.
Through a number of studies for major oil companies we have acquired a solid database and a good overview of the technical and economical challenges which must be met and the safety requirements that have to be adressed. This paper will outline the unique features of a floating LNG production facility based on the spherical tank system. It will be shown how the overall safety is enhanced through the use of the spherical tank and how it can be adapted to suit requirements for harsh as well as mild weather conditions, different production capacities and feed compositions.

INTRODUCTION
Although having been the subject of numerous concept studies and proposals for the last years, the idea of LNG production on a floating structure is by no means new. In the mid-to late 1970's a LNG FPSO was offered to Iran for the Kangan field. A full basic engineering design including comprehensive safety assessments was carried out and Det Norske Veritas prepared a Rule Proposal. The unit consisted of 6 spherical LNG tanks and a 2-train APCI process in a steel hull. The hull was weathervaning on a single point mooring and the unit had a LNG production capacity of 2,8 MMTPA and a storage capacity of 165 000 m3.
Complete front-end engineering was carried out for this project including comprehensive risk assessment. The project was terminated for political reasons. The main features of the Kangan LNG FPSO are shown in Figure 1.
Figure 1 - General arrangement and main features of the Kangan LNG FPSO(Available in full paper)
Since then, a number of concept studies have been done for oil companies on the same subject. However, recently these activities have become more and more frequent due to thegeneral interest throughout the LNG industry.
Design, Manufacture, and Installation of the Typhoon Project Flowlines
Authors: Roseboom Kenneth W. , Kaplan Keith B. , Sawyer Martin A. , Lecomte Hubert , Hogben Stan 
Published: October 2008

Abstract
The Typhoon Field development required 9,000 psi MAWP flowlines from the four subsea wells to the TLP. An overview is presented of the design, manufacturing and installation of these four flexible flowlines. The flowline design required the use of insulation for flow assurance, start-up fluid considerations in the carcass metallurgy, and tensile and armor wire design for the testing and operation conditions. Because the design temperature caused aging concern for the Polyamide-11 (PA-11) pressure sheath, additional manufacturing requirements were placed on this flexible pipe component. Additional testing and inspection was also performed due to the high-pressure application. A flowline and associated umbilical installation overview highlights the use of diverless bend restrictor to I-tube connectors, brine filled flowlines for start-up hydrate inhibition, wellhead Staband-Hinge-Over connections, subsea heat exchanger installation, and installation sequence considerations. Lessons learned from this project scope are presented.

Overview
The Typhoon Field is in Green Canyon Block 236 and 237 in approximately 2,100-ft water depth. Equity is fixed at 50% Chevron and 50% BHP Billiton, with Chevron the designated operator. The discovery well was drilled in April 1998. The Typhoon Project was sanctioned in January 2000 for the development of 4 subsea wells produced to a centrally located TLP. First oil was achieved from the field on July 29, 2001. All four wells were on production at full rate by August 16, 2001, which was 54 days after the installation of the TLP.

Design

Design Basis.
The flowline design was based on a well shut in tubing pressure (SITP) of 9,000 psi. The flowlines for the field connect 4 subsea wells offset from 3,000 ft. to 9,800 ft. to a TLP centrally located in the field. Design maximum flowrates were up to 22,000 BOPD for the most productive well in the field. The wax appearance temperature was 82 °F. Because the wells were centrally located with relatively short offsets and wax plugging was not thought to be a major concern, a single flowline for each well was determined to be adequate. Flowline routing was required to avoid a methane gas vent area and possible chemosynthetic community area(Figs. 1, 2 & 3).
Of concern in the design requirements were the well head temperatures. The temperature forecast for the hottest well in the field, the GC237 No. 2 well, was for an initial wellhead temperature of 184 °F. For flow assurance reasons the overall heat transfer coefficient for the pipe was required to be 1.7 BTU/hr-ftÂ2-°F.
The flowline design was specifically engineered for the Typhoon field conditions. Although the well lives were expected to be less than 7 years, the fatigue and corrosion design was based on a 20 year design life requirement. The design life for the pressure sheath layer in the flexible pipe was allowed to be 10 years based on the maximum expected heat content from the flow stream.
Investigation of Gas Dispersion and Explosions in Offshore Modules
Authors: Johnson D.M. , Cleaver R.P. , Puttock J.S. , Van Wingerden C.J.M. 
Published: October 2008

Abstract
There has been considerable progress over the last decade in validating models to predict the loading resulting from an explosion in an offshore module. However, much of the experimental work that provided the validation of the models has involved using idealized gas clouds, generally natural gas or methane at a single concentration throughout the whole volume. This paper describes an experimental project and modeling work undertaken to provide a more realistic representation of the risks posed by gas explosions in offshore platforms. The project involved laboratory, medium and large scale experiments, examining the effects of realistic fuel mixtures, realistic gas release conditions and nonhomogeneous gas clouds filling only a portion of the module. Comparison with gas dispersion and explosion models was also carried out.

Background
The Blast & Fire Engineering Project for Topside Structures [1] was initiated in May 1990 to study the special explosion and fire hazards facing offshore operators. The objective of Phase 1 of this joint industry project (JIP) was to provide interim guidance to designers and operators to reduce the potential for a major disaster offshore as happened on the Piper alpha platform in 1988. In addition to providing this interim guidance, this project recognised that there was a need to obtain data on these hazards from full-scale experiments. Therefore, as part of the follow-on Phase 2 project, a series of experiments was undertaken to obtain quantitative data on the explosion hazard in full-scale geometries truly representative of the offshore environment [2].
The results of this project indicated that high explosion overpressures could be generated and that water sprays activated prior to ignition could significantly reduce these overpressures. As a consequence of these findings, the UK Health & Safety Executive (HSE) commissioned a further project, known as Phase 3A [3], in which experiments were undertaken to identify methods of reducing the severity of explosions.
The Phase 2 and Phase 3A projects showed that it is generally not practical to design an offshore platform against the ‘worst case’ explosion. Therefore, a risk based approach for design against explosion hazards is needed in which the risks are reduced to as low as reasonably practicable. In taking a risk-based approach, it is important that the full spectrum of possibilities is adequately understood. This includes scenarios involving ignition of a non-homogeneous gas cloud occupying only part of the module. The Phase 2 and 3A projects had, however, been conducted with homogeneous gas clouds throughout the full module, and in most cases the mixture had been at a stoichiometric concentration. This was appropriate at the time, as it was necessary to understand of the scope of the explosion hazard and to provide well defined experiments against which explosion models could be validated. However, there was a clear need to investigate more realistic conditions.
The Discovery of U-166: Rewriting History with New Technology
Authors: Church Robert A. , Warren Daniel J. , Hill Andrew W. , Smith Jonathan S. 
Published: October 2008

Abstract
During World War II, Hitler sent several of Germany's Uboats to the Gulf of Mexico to conduct warfare on merchant shipping and halt petroleum shipments. In less than a year, fifty-six merchant vessels were sunk and several others were severely damaged. During that entire operation only one Uboat was lost in the Gulf of Mexico. That U-boat was the U- 166. Since 1942 the U-166 was thought to have been sunk by the U.S. Coast Guard south of Isle Dernieres, Louisiana in the South Timbalier Area. Numerous surveys have crossed the area, but no trace of the U-166 was ever identified until recently.
In 2001, C & C Technologies, Inc. (C & C) began using the HUGIN 3000 AUV for offshore oil and gas surveys in the Gulf of Mexico. While conducting a pipeline survey for BP Exploration and Production Inc. (BP) and Shell International (Shell), C & C's marine archaeologists identified a sonar target in the vicinity of the shipwreck, Robert E. Lee, which they thought might be the long sought after German U-boat, U-166. The oil companies approved further investigation with the HUGIN 3000, which revealed spectacular sonar and multibeam bathymetry images lending further evidence to the U-boat hypothesis. On May 31 a research team from C & C, the Minerals Management Service, BP, and Shell conducted an ROV investigation of the site confirming the identity and location of U-166 and its last victim, the Robert E. Lee.

Introduction
In January 2001, BP and Shell contracted C & C to survey a route for the Okeanos pipeline. In doing so BP and Shell supported the use of a newly developed deepwater survey vehicle. C & C would use their new HUGIN 3000 AUV, a state of the art deep-water survey vehicle. This AUV carries a full array of survey instruments and is capable of faster and more accurate surveys than conventional deep-tow systems. The oil companies willingness to take advantage of this new technology lead to an astounding discovery that helped solve a captivating historical mystery in the Gulf of Mexico.
The HUGIN 3000 AUV (High Precision Untethered Geosurvey and Inspection System, Autonomous Underwater Vehicle) is a third generation AUV by Kongsberg Simrad and the first commercially operated AUV capable of surveying to 3000 meters water depth. The HUGIN 3000 is the result of the cooperative efforts of C & C and Simrad, and was developed out of a commitment from BP for next generation survey technology.1 This AUV is integrated with a multiinstrument survey payload consisting of a Simrad EM 2000 (200 kHz) swath bathymetry system, dual frequency Edgetech Chirp side scan sonar (120 kHz and 410 kHz), and an Edgetech Chirp subbottom profiler. Because it is an untethered system, running on internal power, it can operate even in rough seas at faster speeds with greater mobility and accuracy than conventional towed arrays.
Thales GeoSolutions AUV Sensor Integration
Authors: Cannon Stewart 
Published: October 2008

Abstract
Traditional AUV development has involved designing a vehicle, making it operational and then fitting available sensors to it. The Thales approach has been to integrate the vehicle and sensor systems during the design stage. This has produced a highly integrated system that is smaller and lighter than contemporary designs. This paper describes the results of this integration and the performance of the vehicle and sensors produced by the design.

Introduction
AUV's have caught the offshore industry's imagination and are being billed as the weapon we will be doing battle with in the future. A quick survey of AUV's currently operating or in late stages of development for commercial operations shows an amazing range of sizes and shapes and very few design trends. On the one hand are very large vehicles that are designed to operate at speeds up to eight knots and at the other extreme are small vehicles designed to operate at more limited speeds with multiple vehicles. We at Thales GeoSolutions have chosen the latter approach.
From personal experience with AUV's dating back a number of years it appears that many designs have evolved from a generic AUV into a survey tool merely by adapting sensors to an existing vehicle design. With the Sea Oracle we have had the luxury of designing a vehicle around a sensor. One area of agreement there seems to be in the commercial AUV marketplace is that multibeam echo sounder data collection is the most important task for AUV's. Therefore the Sea Oracle AUV has been designed around a multibeam echo sounder system.
The Thales GeoSolutions Sea Oracle AUV is based on the third generation Odyssey class vehicle designed by Bluefin Robotics. Bluefin are a spin-off from MIT's Sea Grant AUV lab and produce military vehicles and science vehicles along with survey vehicles in commercial partnership with Thales GeoSolutions. The MIT lab's Odyssey II class vehicles developed many new AUV technologies such as a monocoque hull. The main feature of the Odyssey II class AUV of interest to Thales GeoSolutions was its simplicity. Since they didn't have hovering thrusters and were capable of simple mission profiles they were able to focus on the problems specific to AUV's and were able to gain valuable experience an a large number of dives.
Figure 1. Odyssey II Class AUV.(Available in full paper)
Bluefin, in conjunction with the Monterey Bay Aquarium Research Institute (MBARI) then produced a design for an Odyssey III class vehicle that would be configurable for different missions. The resulted in a vehicle that was tubular, 21 inches in diameter and had three or more separate sections. The key to the design was a common tail section that contained the propulsion, control, main vehicle computer, navigation system and communications. Essentially the tail section was the AUV.
An Introduction to Marine Electrical Methods: Towed Resistivity & Towed Induced Polarization Applied to Marine Geotechnical Problems
Authors: Graham Richard F. 
Published: October 2008

Abstract
The geoelectric methods of DC resistivity and induced polarization (IP) have had a long history as complementary geophysical tools with which to remotely explore the earth. Pioneering work on both techniques dates to earliest part of the last century. Resistivity had gained industry acceptance well before the middle of last century; while due to its more sophisticated hardware requirements, IP's commercial establishment lagged until the later half of the last century. The ability of marine towed resistivity systems to quickly and effectively categorize sediments in the near subbottom has been commercially demonstrated in the telecommunications industry. The application of DC resistivity to other geotechnical problems is discussed. Also discussed are the limitations of DC resistivity and the application of marine towed IP to problems where DC resistivity falls short.

Introduction
Williamson & Associates has figured prominently in the relatively brief history of the application of electrical methods to marine geophysical survey. First, in the early 1990's, in partnership with Cable & Wireless Marine, Ltd. (now Global Marine Systems, Ltd.), Williamson & Associates launched the first commercial foray into marine resistivity with the commissioning of two C-BASS (Cable Burial Assessment Survey System) sleds. The C-BASS program was followed by second partnership, this time with Sage Engineering, Ltd., (now Thales, Inc) leading to the development of two deeptowed ReDAS (Resistivity Data Acquisition System) systems.
Both the C-BASS and ReDAS survey platforms are bottom-towed sleds capable of taking continuous multielectrode, resistivity measurements of the top few meters of seafloor while working in water depths exceeding 2000m.
The C-BASS weighs approximately 1ton and when compared to ReDAS, is a more fully instrumented platform incorporating a sub-bottom profiler, lights and a video camera, a CTD and a mini-CPT (Cone Penetrometer). ReDAS is primarily a resistivity data collection system, and is smaller and lighter than the C-BASS, weighing approximately 1/2ton. Both are easily deployed from survey-class vessels using standard "deep-tow" oceanographic winches and A-frames.
With regard to their resistivity measurement systems, though different in detail, C-BASS and ReDAS have very similar performance characteristics. This is due largely the fact that both systems were targeted at the telecommunications industry and were therefore tuned to requirements of the cable burial assessment (BAS) surveys.

Towed Direct Current (TDC) Method.
Both C-BASS and ReDAS can be considered marine Towed Direct Current systems and are treated the same for purposes of this discussion-in the details of the systems lie subtle differences.
Land-based towed array resistivity systems have been available for some time. However, the performance of these land-based systems is often quite poor, with the data quality being limited due to inadequate coupling of the electrodes to the ground.
Seeing Through Crude Oil- Results from Demonstrator
Authors: Hother John A. , Cockshott Robert A. 
Published: October 2008

Abstract
Results from a development model downhole video imager operating in crude oil are presented. Pictures of representative items captured at the video output show that the system provides high quality images of objects immersed in crude oil.

Introduction
Proneta has identified, and patented, a way to see through crude oil, which will have a range of applications in the oil and gas industry. The first application we have explored is a new form of downhole video that requires no preparation of the well, saving time and cost in interventions. The previous paper SPE 71465 [1] reported the results of the successful feasibility study. This paper presents the results from the demonstrator, the first phase of the current operator-sponsored Joint Industry Project.

Demonstrator imager
The demonstrator tool comprises a self-contained imaging and illumination system in a cylindrical housing, which is sealed to withstand immersion in crude oil. Two versions were assembled and tested: one downwards-looking (figure 1) and the other sideways-looking (figure 2). While not engineered to withstand full down-hole conditions, both configurations are representative of practical tools and all the necessary optics and electronics have been accommodated within the space constraints of a deployable system.

Test set-up
Crude oil was placed in a steel tube large enough to contain the imager and target objects. The imager was mounted on a moveable frame above the tube, and could be lowered in and out of the oil and moved sideways in two axes. Figure 3 shows the moveable frame and the imager in the oil-filled tube.
Crude oil samples were obtained from various North Sea fields, including Scott (Amerada Hess), Fulmar (Shell) and Banff (Conoco), and a pumping system allowed the tube to be filled and drained during the tests. Water droplets and gas bubbles could also be introduced into the oil to investigate imaging through water and gas.
The output from the tool was connected to an image capture system, allowing video and still pictures to be displayed and stored. All images presented in this paper are stills taken from the imager's video output.
Osprey Project: Design and Installation of a Novel Platform in Cook Inlet, Alaska
Authors: Visser Robert C. , Carlson Gary E. 
Published: October 2008

Abstract
The paper describes the design, fabrication and installation of a novel self-erecting platform in Cook Inlet, Alaska. The platform project was completed by Forest Oil Corporation at a fraction of the cost of a conventional platform, thereby allowing exploration and subsequent development of a hitherto noncommercial oil field discovery dating back to 1969. This was accomplished despite the fact that Cook Inlet is one of the most inhospitable offshore areas in the world; there are thirtyfoot tides, moving ice floes in the winter and there are no derrick barges. The platform was assembled in a floating floatover operation in a deep-water bay in lower Cook Inlet. The assembled platform, supported on a barge, was towed to location in upper Cook Inlet and held in place at high tide with several tugs. As the tide ran out the legs reached bottom and the barge was removed. Foundation piles were driven using the pre-installed platform cranes.

Introduction
The Redoubt Shoal field in Cook Inlet, Alaska, see Figures 1 and 2, was discovered by Amoco (then PanAm) in 1969, but was not deemed commercial at the time. Forest Oil Corporation (then Forcenergy) took over the acreage in 1996 and, following a 3D seismic survey, concluded that the field could be commercial. To confirm this, however, required the drilling of at least two and possibly four appraisal wells.
Confirming the commerciality of an offshore prospect is usually done by drilling one or more expendable appraisal wells with a mobile drilling unit. For remote Cook Inlet this method is cost prohibitive, because the equipment has to be mobilized from out-of-state and a single appraisal well was estimated to cost some $25 to 30 million in 1997. Installing a platform in Cook Inlet the "conventional" way is also cost prohibitive, because there is no longer any heavy lifting equipment available on the West Coast and such a platform was estimated to cost $ 60 to 80 million.
As an alternative Forest decided to investigate the possibility of installing an "exploratory" drilling structure. Requirements for a minimum structure were:capability to support a 20,000-foot modular drilling rig,installation without heavy lifting equipment,feasibility to be converted into a permanent platform,easy removal in case the prospect did not pan out, andrelocatable to another Cook Inlet location.
A number of alternative platform concepts were developed by Redondo Beach, California consultant Belmar Engineering and further investigated for feasibility by Brown & Root in Houston. The selected concept requires no heavy lifting equipment and uses the tide to install the platform. To keep costs down, the platform, which was named Osprey, is located in 45 feet MLLW about two miles from shore rather than in much deeper water, four miles from shore, where the Redoubt Shoal field is located. The lower platform and future pipeline costs offset the increased extended reach drilling costs.