bluuebunny/crossref_metadata_2025_split huggingface dataset:
Membrane Technology for Offshore LNG
Authors: Deybach Frédéric 
Published: October 2008

Abstract
Environmental and financial issues will make LNG FPSOs and LNG FSRUs a reality.
The technical specificity of the membrane technology, with an outstanding record on LNG carriers, make it particularly adequate for offshore applications. Cost effective and reliable it also offers a great operational flexibility.
It has already found its first application in the LNG offshore industry : El Paso LNG Bridge? are being currently built in Korea.

Introduction
The membrane containment system is widely used on LNG carriers and it has been so for more than 30 years with an outstanding record for safety and reliability (two third of current new orders are placed with membranes). After reviewing some of the history of LNG, the nature of the membrane technology is described.
Environmental and financial issues that will make LNG FPSOs and LNG FSRUs a reality are addressed. Issues such as the growing concern about the location of gas terminals, and of course the benefit of having a mobile unit transferable to any part of the globe.
The technical specificity of the membrane make it particularly adequate for offshore applications:Large free open deck available for the installation of a liquefaction or a regasification plant.A containment system designed to withstand liquid motion and allows for all filling levels.Safety heightened by a strong and simple design of the hull structure, by a low windage area and by a continuous monitoring of membrane tightness.Light components allowing for on-site repairs & maintenance.Operation flexibility with no continuous cooling down required.

Background
The commercial use of Liquefied Natural Gas (LNG) was introduced in the 1960's to monetize natural gas reserves that were remote from the consumers. In order to transport this gas on long distances with no consumer on the way, the most cost effective way was to place it on ships. To maximize the amount transported, the cargo is liquefied to take advantage of the density increase (multiplied by nearly six hundred (x600)). The pressure at which natural gas remains in its liquid form at ambient temperature being unacceptable, LNG is stored and transported at ambient pressure and low temperature : -163°C. This low temperature is maintained by insulating the liquid from outside heat. Today this principle is applied both for land storages and for LNG vessels.
The containment system of the LNG must therefore face two challenges : resist such low temperature and provide sufficient insulation to keep natural gas in its liquefied state. A third challenge is of course to do that in a cost-effective way. Today, three metallic materials are used that retain ductility at this temperature : aluminum, stainless steel and nickel steel. Two different approaches have been developed : self supporting tanks (the structure of the tank in contact with the LNG is able to resist by itself the pressure of the cargo column) and membrane tanks (the membrane contains the cargo but relies on the ship / building structure to resist the pressure).
Operational safety analysis of FPSO - Shuttle Tanker collision risk reveals areas of improvement
Authors: Vinnem J.E. , Hokstad P. , Dammen T. , Saele H. , Chen H. , Haver S. , Kieran O. , Kleppestoe H. , Thomas J.J. , Toennessen L.L. 
Published: October 2008

Abstract
The risk of collision between shuttle tanker and FPSO during off-loading is strongly dependent on Human and Organisational Factors. The contributions to the collision frequency have been analysed in terms of Risk Influencing Factors, which are structured in an extensive risk influence diagram. Contributions from various Risk Influencing Factors is achieved by data from incidents and near misses, as well as from expert meetings. Recommendations for risk reduction are presented in relation to field configuration, minimum time to be available for recovery from drive-off scenarios, as well as crew competence, positioning systems, interface on shuttle tanker, FPSO and between the vessels.

Introduction
Turret moored FPSOs of the mono-hull type have been used in the North European waters since 1986 [Petrojarl I], so far without serious accidents to personnel or the environment. The use of such vessels for field development has increased during the last 5-10 years, and in these waters more than 25 fields are currently either in operation or being developed with FPSO units, mainly new built vessels.
The vessels being installed in the North Sea, North Atlantic and Norwegian Sea fields have traditionally been designed for considerably higher environmental loads and often also higher throughput as compared to installations in more benign waters. Without exception, the ones so far installed or under construction for these areas have what is termed 'internal' turret, in the bow or well forward of mid ships, with transfer of pressurized production and injection streams through piping systems in the turret.
Although FPSOs are becoming common, operational safety performance may still be considered somewhat unproven, especially when compared to fixed installations. Floating installations are more dependent on manual control of some of the marine systems, during normal operations as well as during critical situations.
Accidents are often initiated by errors induced by human and organisational factors (HOF), technical (design) failures or a combination of these factors. Effective means to prevent or mitigate the effects of potential operational accidents are therefore important.
The overall objective of the programme was presented in Ref. 1. The programme has considered the following phases:Methodology development1996-1997: Pre project, definition phase1997-1998: Analysis of riser damage, inadequate turret operations1999-2000: Collision with shuttle tanker (ST)Collision Frequency Study2000-2002: Extended study of collision risk The work up to 1998 has been summarised in an OTO report (Ref.2), published by the UK Health and Safety Executive (HSE). The details of the analysis during 1999-2002 are presented in Refs. 3, 4, 5 and 6, of which the latter is published by the HSE. This paper is a summary of the work carried out during 2000-2002.
Quantifying Risks of Well Intervention, Oil Deferment and Loss of Reserves in Complex Smart Wells
Authors: Hother John , van Dongen Hans , Braithwaite Steve 
Published: October 2008

Abstract
This paper reports on the results of a Reversionary Mode Analysis Level-1 (RMA-1) to assess the 'do-ability' of three novel, complex, smart well designs. These are the Spider Well?, the Stacked Internal Gravel Packs (IGPs) and the Smart Wells options studied for a deepwater sub-sea field in the Gulf of Mexico.
Both the Spider Well?and the Stacked IGPs designs are more complex than Smart Wells, which in turn are more complex than conventional wells. These complex smart wells contain more equipment, which complicates the installation of the wells, and which must function for the lifetime of the well. In addition, several equipment items to be incorporated in the wells require new designs, or pressure rating extensions of existing technology.
Whole life-cycle plans were defined for each of those three well design options. Quantitative failure mode analysis incorporating economic consequences were performed on all well construction processes and production subsystems. The RMA software calculated "Risk-Dollars" by multiplying the probability of failure by the consequential costs of well intervention, oil deferment and/or loss of reserves.
The resulting risks were broken down into production system and construction process elements, and into the economic categories of intervention, deferred production and lost reserves. The assessed risks, together with various other factors, were input to the selection process of the preferred field development concept, which is outside the scope of this paper. Key risk drivers were identified from the analysis, allowing cost-effective targeting of reliability improvement actions. The three designs studied, the analysis method and the results are presented in the paper.
The use of quantitative risk results, expressed in economic terms, has wide application in making systematic comparisons between complex systems, both inside and outside the energy industry. The results clarify the reliability risks present in smart wells, even before considering more advanced alternatives.
The results show that failures are inevitable in all three options, but the Spider Well? carries the greatest overall risk, the highest total number of failure modes and more high-cost failures. The RMA method demonstrated its strength in being able to identify critical risks and 'drill-down' to root causes, allowing specific mitigating measures to be identified and evaluated. These included specific full-scale testing of prototype equipment, and specific quality management and reliability engineering measures. It was found that these mitigating measures, if implemented, would bring the risks to similar levels for all three well design options. Sand control failures present the largest remaining risk.

1. Introduction - Purpose And Objectives
This RMA-1 project was to assess the risks associated with a deepwater development opportunity comprising 8 stacked oil sands at 6,000 m in the Gulf of Mexico.
HPHT Well Control; An Integrated Approach
Authors: Rommetveit Rolv , Fjelde Kjell Kåre , Aas Bjarne , Day Norman F. , Low Eric , Schwartz David H. 
Published: October 2008

Abstract
This paper presents an integrated approach on HPHT well control in narrow pressure margin wells. The approach includes theoretical evaluations, computer simulations with advanced modeling tools, laboratory studies, well control training as well as implementation of learnings in procedures and operations. Examples from the North Sea on the application of advanced transient well control modeling for the planning of HPHT drilling as well as training are described in detail.
A special focus is directed towards gas diffusion during drilling operations; with its impact on a number of important parameters like rheology and barite sag. Both theoretical and experimental work is presented.

Introduction
The drilling of HPHT wells pose special challenges compared to standard wells:High pressures and temperatures impact mud properties in a dynamic way, and can have effects on well controlSmall margins between pore and fracture pressures will prevail in sections of the wellThe conditions are above the critical point for the gas/oil/condensate influx; which means that the hydrocarbon influx is infinite soluble in the base oil of the mud.Hydrocarbon influx will totally mix with the base oil in oil based mud (OBM), and infinite amounts of gas can dissolve in the mudDrilling of inclined and horizontal wells will make the consequences of barite sag seriousSignificant quantities of gas can diffuse into a horizontal section of a well if OBM is used even if the well is overbalanced The frequency of well control incidents is higher than one per HPHT well, and an increasing number of these take place during completion.

The Physics of an HPHT Well
An HPHT well can be categorized as an integrated physical system. The well is defined as the flow conduit from the mud pump down the drill string, drill bit and up the annulus to the mud pits; with the drilling mud, etc. filling up this flow conduit. Maintaining the control of the well at all times is a question of understanding the physics of the well during changing conditions and using this knowledge to optimize the design of the well, to develop sound drilling procedures and to handle unexpected situations during drilling in an optimal way.
Traditional and well proven drilling practices and rules of thumb have been developed by "trial & error". In many cases, these represent optimal solutions. However, when the drilling situation differs significantly from the traditional, old rules may not apply, and one will need to analyze the problems scientifically to revise the practices. One can use transient computer models with the correct physics built into them to develop new procedures and practices for these wells.
Below the main physical parameters and interactions are discussed.
Next Generation Drill Pipe for Extended Reach, Deepwater and Ultra-deep Drilling
Authors: Jellison Michael J. , Payne Mike L. , Shepard Jeff S. , Chandler R. Brett 
Published: October 2008

Abstract
A new drill pipe size, 5-7/8 in. OD, represents enabling technology for Extended Reach Drilling (ERD), deepwater and other deep well applications. Most world-class ERD and deepwater wells have traditionally been drilled with 5-1/2 in. drill pipe or a combination of 6-5/8 in. and 5-1/2 in. drill pipe. The hydraulic performance of 5-1/2 in. drill pipe can be a major limitation in substantial ERD and deepwater wells resulting in poor cuttings removal, slower penetration rates, diminished control over well trajectory and more tendency for drill pipe sticking.
Hydraulic pressure losses are minimized with 6-5/8 in. drill pipe, but 6-5/8 in. drill pipe is an "over-design" solution in many cases. The 6-5/8 in. drill pipe is difficult to handle, requires excessive physical space on the rig, can limit setback capacity and generally requires significant rig handling equipment modifications. In addition, 6-5/8 in. drill pipe cannot be used to drill inside of 9-5/8 in. casing and 8-1/2 in. hole sections.
The 5-7/8 in. drill pipe provides a significant improvement in hydraulic efficiency compared to 5-1/2 in. drill pipe and does not suffer from the disadvantages associated with use of 6-5/8 in. drill pipe. It represents a drill pipe assembly that is optimized dimensionally and on a performance basis for casing and bit programs that are commonly used for ERD, deepwater and ultra-deep wells.
Realizing the full potential of 5-7/8 in. drill pipe requires a high performance tool joint connection. A second-generation double-shoulder tool joint connection, optimized for 5-7/8 in. drill pipe, provides exceptional torsional strength combined with a streamline configuration. Configured with a 7 in. OD tool joint the connection permits fishing inside of 9-5/8 in. casing or 8-1/2 in. open hole sections.
The first string of 5-7/8 in. drill pipe went to work on a Gulf of Mexico project in July 1999. Since that time more than 830,000 ft of 5-7/8 in. drill pipe comprising over 40 drill strings has been manufactured and put into the field. The drill pipe has been successfully used to drill ERD, deepwater and ultra deep HPHT wells in the South China Sea, Gulf of Mexico, Offshore Trinidad, Onshore Wyoming and Onshore Colombia.
The 5-7/8 in. drill pipe has improved penetration rates with large diameter bits and significantly shortened drilling curves to total depth in established fields. Drilling engineers are currently evaluating 5-7/8 in. drill pipe for use on major ERD, deep directional and deepwater projects in various parts of the world.
The paper discusses the engineering philosophy behind 5-7/8 in. Extreme Reach (XR) drill pipe, the design challenges associated with development of the product and reviews the features and capabilities of the second-generation double-shoulder connection. The paper provides drilling case history information on significant projects where the pipe has been used and details results achieved with the pipe.
Devils Tower Export Lines: 160 Miles of 18" OD Reeled Rigid Pipe
Authors: Menier Philippe 
Published: October 2008

Abstract
The Paper starts with a summary of the Devils Tower development in the GOM and gives the characteristics of the 18" Oil and 18" gas export lines from the shallow water platforms to the deep water terminations. It continues with the description of the sub-sea tie-ins branch in 14" diameter from the export lines to the SPAR in 5000' water depth including the Steel Catenary Risers at SPAR. Provisions for futures ties-ins of nearby fields will be covered.
The application is any deep or ultra deep development up to 7,500' water depth of rigid or flexible flow-lines, steel catenary risers and umbilical.
The paper will give the elements to assess the performance of the Deep Blue / Theodore spool-base spread. Weather sensitivity and offshore performance is analyzed and the advantages to S- lay laying method in terms of safety and quality and further developed.
The high capability of the Deep Blue combined with the Theodore, Alabama onshore spool-base has offered an economic alternative to the conventional S-lay laying method for the Devils Tower development. It can be further applied to any mid-size rigid pipe flow-lines SCR installation in deep waters. It combines the advantages of the low cost steel pipe, of the large onshore line pre-fabrication and of the reduced offshore installation time.
Devils Tower Development Overview
Discovered in 2000, The Devils Tower field is located in Block MC-773 in the Mississippi Canyon, 140 miles southwest of New Orleans, in the Gulf of Mexico. The development by Williams Field Services Company consists of a SPAR platform in 5610 ft of water, and two export pipelines totaling approximately 165 miles of pipes. Technip Offshore has been contracted by Williams to design, supply and install the Mountaineer Oil Export Pipeline connecting the Devils Tower field to MP 313 platform and the Canyon Chief Gas export pipeline connecting the Devils Tower field to MP 261 platform. From the SPAR two 14" steel catenary risers run into two 14" sea-lines 6 miles long to tie-in point to the tow 18" export pipelines. From this point the two 18" main export pipelines run in parallel on the seabed, northerly towards block MC 114. At this point the Oil export continues north to the MP 313 platform, the Gas export line continues northeast to MP 261 platform. Both lines tin-in to shallow platforms via an 18" riser.
The SPAR will be able to handle 60,000 barrels of oil per day. The Mountaineer pipeline will have a capacity of 150,000 bpd; the Canyon Chief pipeline will have capacity of 350 million cubic feet of gas per day.
Figure 1. Devils Tower Deepwater Development Project(AVAILABLE IN FULL PAPER)

Technip-Coflexip Scope on Devils Tower
The Epic contract includes all necessary tasks to hand-over to Williams Field Services a complete pipeline system ready for production.
Feasibility Of a Lightweight Buoy Mooring Concept
Authors: Schwartz Arnold , Chen Philip M. 
Published: October 2008

Abstract
This paper describes the feasibility analysis and field test of a novel buoy mooring concept.* Successful field tests on the Severn River near Annapolis, Maryland, indicate that the concept is ready for engineering development. The technique allows for repeated latching to and release from a bottom emplaced anchoring station. Means are provided for relocating the bottom anchoring station, which may be very accurately positioned at initial emplacement. Thus, the need for resetting heavy anchors every time a lightweight buoy must be restationed can be eliminated.

Introduction
A major concern of those who use the waterways for travel and commerce is accurate knowledge of local bottom topography. This concern is seen in the duties of the sounding man made famous by Mark Twain and other writers. Indeed, Samuel Clemens adopted the call of the Mississippi river pilots "Mark Twain", indicating a depth sounding of two fathoms, as a pseudonym for his novels of river life. Aids to navigation can be considered as the traffic signs of waterways. They serve to channel traffic, warn of danger, and alert mariners to their location. The United States Coast Guard is responsible for the accurate deployment and maintenance of buoys in our nation's navigable rivers, lakes, and coastal waters. In certain areas, particularly the Great Lakes, this responsibility necessitates the annual deployment and retrieval of these buoys together with their mooring chains and concrete block anchors. The mass retrieval of these buoys is a preventive measure to protect the buoys from ice damage in the winter months. This repetitive operation involves excessive ship operational time as well as the gross expenditure of materials and labor.
Present technology has advanced to enable the development of lightweight buoys. These can be constructed of such advanced materials as sandwich cores, glass-reinforced plastics, or composites, and can reduce the arduous task of buoy deployment. In fact, the lightweight buoy would lend itself to deployment from a small tender or buoy boat. The problem still exists, however, of handling the 2000-lb, or greater, anchor that must be annually deployed and retrieved from rather sizable vessels.
A requirement exists for a device or system that can accomplish repetitive mooring of lightweight buoys in water of less than 100-ft depth. Such a system must be inexpensive, simple to operate, reliable, and deployable with high accuracy in repetitive moorings.

Introduction (Continued)
The Coast Guard does not necessarily have to identify every natural or manmade hazard. However, when they do mark such hazards in the interest of safety to navigation, they must do so accurately and competently. This fact has been seen in such litigation as SOMERSET SEAFOOD COMPANY versus the UNITED STATES (193F. 2d 631, 1952) where the responsibility of accurately stationing buoys was clearly established. In this case, a commercial vessel was sunk by a submerged wreck which was marked by an adjacent Coast Guard buoy.