bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tandem Transfer of LNG - Interface with the Operator
Authors: Cox Phillip John , Jeanneau Eric , Eidem Johan 
Published: July 2010

Abstract
Tandem transfer of crude oil and condensate in dynamic marine conditions has a long history with much accrued experience. Initial systems relied simply on a hawser connection, which was subsequently improved with the advent of Dynamic Positioning Systems.
The new requirement to transfer LNG in true dynamic conditions between two very large floating structures, whilst respecting the stringent rules governing the safety of such operations, has led to the design, testing and qualification of a new heavy duty transfer system, known as the Amplitude-LNG Loading System (ALLS).
The transfer of produced products, mainly LNG but also LPGs and condensate, has to proceed on a regular and repeatable basis, with 2 of the main criteria being:Continuous production and operation of the FLNG over a 20 to 30 year periodProject monetization linked to LNG-C rotations
To ensure that these criteria can live in harmony the LNG transfer system must ensure that the correct volumes of LNG can be safely and efficiently offloaded from the FLNG to the LNG-C whilst minimising the turn around time of the carrier.
The ALLS incorporates a custom built Constant Position Monitoring System (CPMS) which can ultimately be integrated into the DP system of the LNG-C and / or the FLNG, and may eventually lead to on-site operations without the need for a hawser link. However full analysis of the project specific conditions will be required prior to taking such an important step.
An offshore LNG project is a multi-billion dollar investment, from subsea drilling and development, through construction of the floating process & liquefaction plant (FSPO-FLNG) to operation of a fleet of LNG carriers, some of which may be dedicated on a project basis. As such the reliability and repeatability of the CPMS /
DP couple is a key element in the overall functioning of the offshore LNG transfer system, as any emergency shut down and prolonged interruption in fluid transfer can have significant consequences on the functioning of the FLNG and its capacity limits for storage.
This paper will investigate the history and evolution of tandem transfer in open sea conditions, elaborate on these issues from the points of view of the Client, the Operator and the transfer system supplier, and detail the importance of a fully integrated and modern LNG transfer system.

Introduction
When developing and proposing new methods and systems to the Oil and Gas Industry, especially when safety of personnel and equipment is paramount, co-operation between the main involved parties at an early stage gives a firm base from which to work. In marine environments involving the transfer of LNG and gas, a concerted approach between the end user, the equipment supplier and experienced marine operators will ensure that practical procedures will result whenever possible in similar methods, based on existing know-how.
SS Gas Hydrate: Prediction of Production Test Performances in Eastern Nankai Trough Methane Hydrate Reservoirs Using 3D Reservoir Model
Authors: Kurihara Masanori , Sato Akihiko , Ouchi Hisanao , Narita Hideo , Ebinuma Takao , Suzuki Kiyofumi , Masuda Yoshihiro , Saeki Tatsuo , Yamamoto Koji , Fujii Tetsuya 
Published: July 2010

Abstract
The Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) is planning to conduct production tests targeting methane hydrate (MH) reservoirs located in the Eastern Nankai Trough. Towards the successful implementation of the production tests, MH21 Research Consortium has been evaluating MH reservoirs located in the Eastern Nankai Trough from the viewpoints of geology, geophysics, petrophysics and reservoir/production engineering. Integrating the results of these studies, we have been attempting to construct 3D reservoir models, which have been used to predict the performances of production tests through numerical simulation. This paper presents how we constructed the 3D MH reservoir models integrating the results of the log interpretation and the 3D seismic data analyses. This paper also discusses how the heterogeneities of reservoirs with a different scale such as a fault, dip and change in permeability and a well location affect the test performances referring to the results of the numerical simulation.
Eastern Nankai Trough MH reservoirs are composed of alternating beds of sand layers and mud layers in turbidite sediments. First, the frames of the geological models for the vicinity of the candidate test wells including the faults were defined rigorously mainly reflecting the 3D seismic interpretation results. The insides of the frames were then divided into multiple grid layers replicating alternating sand and mud layers. The distribution of the properties of each grid layer such as lithology, porosity, permeability and MH saturation were estimated by geostatistical techniques using well log interpretation results as a hard data and seismic attributes (e.g., amplitude and acoustic velocity) as soft data. Finally, the geological models thus constructed were converted to the reservoir models by incorporating overburden and underburden layers and by specifying initial pressure and temperature.
Well production test performances were then predicted through numerical simulation assuming the application of the depressurization method. In addition to the base case run, case studies were conducted to examine the effects of reservoir heterogeneities and of well locations, which revealed that the large scale heterogeneities such as sealing capability and conductivity of faults and formation dip affected the short term production test performances rather than small scale heterogeneities like a small change in permeability. Furthermore, these studies showed the benefit of numerical simulation for the design of a field well test.
SS - Gas Hydrate: Microscale Modelling of Dissociation and Formation of Methane Hydrate in Sediment
Authors: Fukumoto Ayako , Sato Toru , Hirabayashi Shinichiro , Brumby Paul , Kiyono Fumio , Ebinuma Takao , Narita Hideo 
Published: July 2010

Abstract
Methane hydrate is a promising energy resource in the near future. One of the processes of its development in the sub-seabed sediments is depressurisation: pumping-up water through a well depressurises down to the extent lower than the equilibrium, and hydrate dissociates. However, hydrate dissociation is endothermic and temperature may become lower than the equilibrium point near a well and, hence, hydrate reforms. This may cause blockage of gas-water flow in the sediment. In this study, heat and mass transfer in water-gas-sand three-phases was analysed numerically by modelling them using a threedimensional lattice Boltzmann method. Sand grains were assumed to be spherical for simplicity and the dissolution of methane into water through the interface was also analysed. At the same time, volumetric rate of hydrate formation was obtained by comparing the model results with those of measurement.

Introduction
Methane hydrate is an ice-like crystal that consists of water as host cage and gas as guest molecules, and exists widely in the sub-seabed sediments and in the permafrost layer, which are under low temperature and high pressure. It is confirmed that methane hydrate contains methane more than that in the form of gas on the earth and has been paid attention as a new energy resource in recent years. To predict the technical and economical feasibilities of its production process, numerical simulations are necessary. One of the processes of its development in the sub-seabed sediments is depressurisation: pumping-up water through a well depressurises down to the extent lower than the equilibrium, and hydrate dissociates. However, hydrate dissociation is endothermic and temperature may become lower than the equilibrium point near a well and, hence, hydrate reforms. This may cause blockage of gas-water flow in the sediment. Therefore, formation of gas hydrate in the sediment should be understood and modelled numerically for the design of its production system. For modelling hydrate formation, its rate is particularly important.
Therefore, it is necessary to estimate the formation of hydrate and the consequent reduction of permeability accurately to predict the production rate of methane gas. In this study, a small high-pressure cell was filled with fine glass beads, methane gas, and small amount of water, and gas hydrate is formed in it by increasing pressure. The same was simulated by a numerical model. As a result, by comparing the both results, a hydrate formation rate was extracted.
Design Methods in ISO 13628-12 and Implications for Gulf of Mexico SCRs
Authors: Sharma Partha Pratim , Song Ruxin , O&apos;Donnell Jeffrey , Mork Kim J. , Kavanagh William Kieran 
Published: July 2010

Abstract
A new riser code, ISO 13628-12 "Design of Dynamic Risers for Floating Production Installations" has recently been updated as part of an industry JIP and is scheduled for ISO ballot in 2010. Once approved, the new ISO 13628-12 will replace the current edition of API RP 2RD as the Code of Practice for the design of dynamic metallic risers for floating production installations. This paper summarizes the four design methods in draft ISO 13628-12 and investigates their implications on the design of future SCRs. The implication of the new riser design code is illustrated by an example of an SCR design in the Gulf of Mexico. Three of the four design methods allow for certain plastic utilization of the riser cross section, which requires additional considerations for design, analysis, material selection and fabrication. Combined loading code checks with the four different methods are performed and the results are compared. Additional material specific considerations including design stress-strain curve and fabrication requirements are also presented.

Introduction
The design methods in the updated draft ISO 13628-12 reflect an evolutionary progression from working stress design to limit state design. Limit state design ensures a consistent safety level, based on acceptable failure probabilities, with due considerations to the inherent uncertainty in the design loads and resistance to such loads. Typical limit states for deep water riser design application include:–Accidental limit state (ALS)–Ultimate limit state (ULS)–Serviceability limit State (SLS)–Fatigue limit state (FLS)
The ALS is associated with events with an annual probability of less than 10-2 and larger than 10-4, while the ULS corresponds to 100 year return period events or events with 10-2 annual probability. The SLS criteria define the loads during the normal operational conditions and normal temporary events. FLS is an ultimate limit state from accumulated excessive fatigue crack growth or damage under cyclic loading.
The performance criteria for the riser design depend on the specific limit state. For example ULS requires that the riser system must survive the design event with no damage, i.e. remain intact and avoid rupture, but not necessarily be able to operate. For ALS the riser system must survive, and may sustain some damage without any rupture i.e. no release of hydrocarbon is allowed. Typical load cases for strength design of SCR are presented in Table 1.
The paper presents a summary of the design equations to assess the capacity of the pipe. The performance of an 18 inch oil (X70 grade steel) export SCR suspended from a semi-submersible in 2000 m water in the Gulf of Mexico is assessed for ULS and the ALS conditions using combined loading equations for internal overpressure conditions. Potential for buckling due to compression in the touchdown zone (TDZ) is also investigated.
In-Service Mooring Inspection for Mobile Drilling Units
Authors: Hall Anthony David , Trower Alastair Michael 
Published: July 2010

Abstract
As with all ‘high consequence of failure’ systems, MODU mooring systems are subject to regulatory inspection regimes. This involves a combination of visual and mechanical measurement techniques that allow classification authorities to judge the onward suitability of individual mooring components.
Traditionally, MODUs have been required to dock or to tie up in-harbour in order to perform mooring inspection requirements. The resulting loss of day rate has rarely been highlighted as a concern, as downtime is often built in to long term contracts. As the drilling fleet ages, scheduled downtime is getting allocated to more significant hull and topsides issues.
The current economic outlook is driving the drilling industry to look at new ways to reduce bottom-line impact of day to day operations. In 2009, Welaptega Marine provided the ability for Pride International to fulfill compliance driven inspections at sea, during rig moves, whilst the MDU was still under contract.
This work has resulted in a new, beneficial approach to MODU operators worldwide. Compared to traditional inspection techniques this approach has been proven to achieve significant time and cost-savings.
Drilling companies are able to perform inspections that meet class and contractual requirements with minor disruption to drilling and rig move schedules.
This paper presents the following:Project background, industry drivers and technologies utilizedDetailed project report of an in-air mooring system inspection conducted in 2009Inspection Methodologies designed to fit-in with daily operations
Ormen Lange Hot Tap Operations - World Record in Hot Tapping
Authors: Apeland Kjell Edvard , Berge Jan Olav , Opheim Birgit S. , Armstrong Mike 
Published: July 2010

Abstract
Over the last 10 years Statoil has developed subsea remote hot tap technology. The first use of the remote hot tap technology was the Tampen Link hot tap in 2008. The hot tap operation itself was performed diverless; however, the preparatory works including hyperbaric welding of the hot tap tee was performed utilizing saturation divers. The world's deepest hot tap operations on a pressurized pipeline were performed on the Ormen Lange field in the Norwegian Sea in August 2009. Two hot taps were conducted in a water depth of 860 meters. These were carried out to tie-in a new seabed template in the southern part of the Ormen Lange field into existing pipeline infrastructure.
The development of the Pipeline Repair System remote hot tap equipment is a result of targeted R&D effort and extensive qualification work over several years. The hot tap technology enables cost-effective modifications to existing pipeline networks without interfering with the ongoing production. The technology is currently qualified to 1000 meter water depth and enables use of any pre-installed hot tap tees. Further development of the hot tap technology, involving development and construction of a retrofit Tee, is ongoing. This will make remote installation and welding of a Tee onto an unprepared deep water pipeline possible.
This paper will describe experience from the development and testing of the Remote Hot Tap system and give an overview of the offshore operations leading to the completion of the world's deepest hot tap operation.

Introduction

What is a ‘hot tap’?
A ‘Hot Tap’ is the process of breaking into a live pipeline (one in which the product is flowing) without interrupting the production to provide a pipeline branch for possible diversion of the flow in either direction. This is normally done by installing ‘tees’ either during the pipe laying process (pre-installed tees, see figure 1) or by retrofitting branch structures after the pipe is laid (retrofit tees). The process involves cutting the membrane of the ‘mother’ pipe through a valve placed on the branch of the tee, extracting the membrane and cutter and then closing the valve until an external connection is made to facilitate the diversion. Figure 2 shows a typical completed hot tap structure showing the ball valve connected to the branch and the spool off the top of the valve connecting to the appended pipeline.
The potential for this technology is the ability to make cost effective modifications to existing pipeline networks without interfering with the original production.
SS: GIS Applications in Marine Geohazards special session: Developing A GIS Data Model For Seabed Site Surveys
Authors: Turner Gareth , Bell Tom 
Published: July 2010

Abstract
Data acquired from site surveys provide an essential resource to various exploration and production activities, such as field development planning, well positioning, and subsea equipment positioning. For many years, site survey data has been delivered as a Computer-aided Design (CAD) product. As operators move into a Geographic Information Systems (GIS) environment, shortfalls from CAD-based workflows have become obvious. This paper presents a method of managing site survey data based on geo-information management principles and practices. The methodology presented in this paper defines a GIS data model for seabed survey data interpretation that satisfies GIS query, presentation, and data exchange purposes. This paper also defines a standard for GIS seabed survey data deliverables from contractors to operators, including methods and processes to move the model to/from CAD-based applications. The implementation of the data model has proven to be a relative success and allows for a better integration of subsurface applications internally. The results have helped define an efficient contractor-operator data exchange process by eliminating data ambiguity and enabling seamless GIS data transfer.
Results have also produced a more intelligent seabed survey GIS dataset with rules and behaviors capability offered by an ArcGIS Geodatabase embedded into the data model. Use of a standard GIS data model and a standard list of GIS data deliverables required from contractors to operators will allow project teams to fully embrace the power of GIS data integration and allow nearly seamless and lossless movement of CAD/GIS representations of the model.

Introduction
In order to reach maximum potential benefit of data provided from seabed site surveys throughout the E & P lifecylcle (Figure 1), there is a need to ensure that data delivered from survey contractors to operators is done so in a structured, efficient, and consistent manner.
SS: New API Codes: Updates, New Suite of Standards: API RP 2A-WSD, the 23rd Edition
Authors: Zwerneman Farrel , Digre K.A. 
Published: July 2010

Abstract
This paper summarizes the updating of API RP 2A Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms - Working Stress Design - API RP 2A-WSD 21st Edition with Supplements 1, 2, and 3, to a 22nd Edition. That 22nd Edition is planned to be the last edition of API RP 2A-WSD.
API RP 2A was due for a revision. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A complete and thorough review of the document was long overdue. The 21st edition was issued in December 2000, Supplement 1 in December 2002, Supplement 2 in September 2005, and Supplement 3 in October 2007. In addition, API desired to incorporate the content from API Bulletins 2INT-MET, 2INT-DG, and 2INT-EX plus accommodate development and alignment of API Recommended Practices 2SIM, 2MET, 2EQ, and 2GEO with ISO. In the process of making editorial revisions, it became obvious that some technical revisions were also needed.

Background
The design process has matured since platforms were first installed in the late 1940's. Figure 1 shows the evolution of offshore platform design in the Gulf of Mexico that has been based upon a combination of events such as hurricanes, development of standards such as API, and advances in industry practices. The first edition of API RP 2A used for designing fixed offshore platforms was published in 1969. Platforms built prior to this were designed to a wide variety of criteria and fabrication techniques. During the 1970's better application of design practices ensured higher engineering standards, until the first modern platforms began to be installed in the late 1970's using a consistent design recipe then available in RP 2A. Platforms installed since the early 1980's provide a more robust design and incorporate many of the lessons learned during the design, installation and operation of earlier platforms.
The significant events occurring in 2004 and 2005 (Hurricanes Ivan, Katrina, and Rita destroying over 120 platforms and damaging an equal number with most of these platforms being fixed based structures installed prior to 1980) led to the issuing of API Bulletins 2INT-MET, 2INT-DG and 2INT-EX in May 2007 in order to respond quickly to industry's needs. These interim documents, the work in progress on RP 2SIM, the planned alignment of API Recommended Practices with ISO and the fact a new edition to API RP2A had not been issued since December 2000 led to the formation of API Task Group 13, responsible for updating RP 2A, with their first meeting held on 25 October 2007. The TG met seven times between October 2007 and December 2009 with some delay caused by the aftermath of hurricane Ike in 2008. The TG submitted final sections of their draft to API on 8th December 2009. Note, the API RP 2A 22nd edition has not been balloted at the time of this paper's submission.
SS: Fiber Moorings, Recent Experiences and Research: Impact of Splinters on Polyester Rope Strength
Authors: Shu Hongbo , Ridge Isabel Mary Louise 
Published: July 2010

Abstract
Foreign objects such as splinters from broken steel wires or wood decks have been found embedded in polyester mooring ropes during handling. Shell initiated an investigation on the impact of such foreign objects on polyester ropes' strength. The laboratory test program was developed with input from the US regulatory authority, MMS. The results of this investigation indicated that the damage mechanism of such foreign objects in fiber ropes is different from what had been covered by the existing industry guidance on damaged fiber rope assessment. This paper presents the outcomes and insights from this investigation to help improve offshore handling of polyester ropes and to provide guidance on how to mitigate the risk if a foreign object is found in a fiber rope.

Introduction
Prior to regulatory approval for operators to use polyester ropes in US Gulf of Mexico mooring applications, a key concern was the polyester rope's resilience to possible handling damage. To address the concern, Shell led a JIP in 1999-2000 to develop a handling procedure and to demonstrate the viability of implementing the procedure on existing anchor handling vessels (Ref. 1). Since 2000, Shell has used polyester rope based moorings in most deep water and ultra-deep water mobile mooring applications (Ref. 2), as well as in permanent moorings such as the Perdido production platform mooring system.
To reduce the mooring installation time window, in 2006 Shell started to explore the possibility of prelaying polyester mooring lines on the sea floor similar to what they did in Nakika field development with steel mooring lines in 2002. In early 2007, a few polyester inserts with regular 20 µm sand barrier were deployed to the sea floor at a Shell prospect in water depth about 7000ft. One insert was connected into a MODU mooring line. Two inserts were recovered a couple of months later, and tested as part of a program to evaluate the impact of sea floor contact on the rope's integrity and strength. A surprise finding was that a few metal ‘splinters’ had penetrated the braided jacket and lodged into one of the ropes (Figure 1).