bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Solution for Tandem Offloading of LNG
Authors: Eide Jorgen , Eide Svein I. , Samuelsen Arild , Lotveit Svein A. , Aanesland Vidar 
Published: October 2008

Abstract
Many oil companies presently work on plans for production of Liquefied Natural Gas on a Floating LNG Production and Offloading (FLPO) vessel. All these schemes require suitable systems for offloading of the LNG to a transport tanker.
Safety and regularity are important issues in design of offshore LNG production and loading systems. In addition to the offloading operation the tanker approach, connect, disconnect and departure phases include critical operations which are weather dependant and may impose restrictions on operability and regularity.
The OCL system is a stern to bow, crane and flexible pipe solution that is developed, based on extensive experience from tandem offloading operations of crude in the North Sea in harsh weather conditions. The system is well suited for LNG transfer where high regularity is required and a large number of cargoes are shipped every year.
The LNG tankers are dedicated transport vessels with modifications in the bow to suit purpose built hawser and loading facilities. When offloading the LNG carrier in a harbor a conventional LNG manifold offloading system in the center of the LNG tanker is used.
In offshore loading, the two vessels are moored together in a "crowfoot" hawser configuration reducing the relative movements between the crane tip on the FLPO and the bow of the tanker. The LNG carrier is operating on constant stern thrust to ensure the required stability of the offloading system in both calm and harsh weather conditions.
Components and sub-systems are selected on basis of functional requirements. Critical components have been qualified in a step-by-step process. The qualification includes development of mathematical tools that have been verified through material testing, model testing and full scale testing. Verification includes design, manufacture and testing of the complete pull-in and connection system as well as full flow testing.
Figure 1 - The OCL LNG transfer system(available in full paper)
Vessel model testing is used both as verification and calibration of the mathematical models and it ensures accurate calculation of the two vessel's motions in the loading area and thus good prediction of the loads on the transfer system.
The flexible pipe is the most critical part of the transfer system. The OCL system is based on a longitudinally welded, thin-wall stainless steel tube corrugated to provide the required bending flexibility. The finished flexible transfer pipe is a lightweight, double-wall construction with vacuum in-between the pipes as thermal insulation.
The qualification process includes full-scale flow testing with both water and LNG. All tests and calculations show that the described solution will allow safe and economic transfer of LNG from a floating production vessel to a tanker.
The OCL LNG transfer system will allow development of stranded gas reserves in areas with no infrastructure, or where a pipeline to a shore facility is not viable or economical.
Classification of LNG FPSOs - A Viable Route For Risk Management
Authors: Ramberg Liv Anette , Skramstad Erik 
Published: October 2008

Abstract
Floating concepts for LNG production and LNG terminals are being evaluated by the industry to meet the increasing worldwide demand for LNG as a clean, environment friendly energy source. Novel technical solutions are required to enable commercially viable developments of remote resources, marginal fields, utilization of associated gas and to provide increased terminal capacity. These new concepts involve a large number of technical uncertainties, large investments and large perceived hazards and this requires effective risk management. In response of this DNV has developed a classification approach for LNG FPSOs, aiming at provision of a structured and predictable assessment of novel concepts.
These classification services and rules for LNG FPSOs draw upon the long experience with risk management of gas carriers and oil producing FPSO's. The classification approach utilizes the best practices both with regard to traditional codes and standards, industry practices as well as use of quantitative risk assessments for decision support among technical alternatives, and qualification procedures for new designs.

Introduction
The demand for natural gas is increasing on a world-wide basis as a result of the increase in the worlds energy consumption, and environmental concern.
Among the fossil fuels available today, natural gas is by far the most clean and environmentally friendly energy source. LNG represents today the most efficient commercial handling and long distance transportation of natural gas.
Floating production of LNG will allow development of remote gas fields and utilisation of associated gas from oil production. Several concepts have been developed recent years concluding feasibility from an economical, technical and safety point of view.
Common to these concepts are that they represents new solutions which not yet have been proven in practice. The following issues represents particular challenges both with respect to the safety for personnel, vessel as well as functional requirements:A highly complex and compact process plant installed in a limited area.Storage of LNG in the proximity of Process equipment and Accommodation.Cargo Transfer in open seas.
Key objectives in the design must be toensure reliable operation.offer adequate protection of personnel including means to ensure safe evacuation and escape.minimize the risk for massive release of LNG from the cargo tanks which can develop into catastrophic scenarios resulting in total loss.
The latter implies that focus must be given to all events with the potential to damage the tanks e.g.escalation of process events to the storage tanks (fire, explosions, dropped objects)tank integritycollisionshull damage, flooding and stability
DNV has identified LNG FPSOs to be an area where we can contribute to our customers needs and demands and we have developed new rules for the Floating LNG/LPG Production storage and offloading units. For this purpose a new class notation was launched in 2001.
Vertor Fidelity Assessment From 4C Seismic Data Recorded on the Seafloor
Authors: Granger P-Y. , Meunier J. , Gratacos B. 
Published: October 2008

Abstract
Vector fidelity is essential for all processing methods dealing with multi-component data and based on elastic wave propagation. However, fidelity cannot be simply assumed: lack of fidelity can introduce severe errors at the early stage of processing the horizontal components. The position of this paper is that there is enough redundancy in the acquired seismic data in order to control the vector fidelity, and when needed, correct for possible departures. The paper analyzes the various causes of vector infidelity and describes practical methods to correct for it.

Introduction
Vector fidelity refers to the ability of the seismic system to reproduce in a faithful manner the particle movement at a precise place and under the excitation of a well-known source. Because vector fidelity is not easy to achieve (especially for the horizontal components) its impact on the final seismic images and results should not be underestimated. Vector fidelity QC is therefore a mandatory step of the processing flow. Vector fidelity depends on many factors related to source, receivers and the experimental conditions. Likewise, measurement and possible departures from fidelity can be corrected in various ways. A check of the required source symmetrical radiation pattern is among the first steps of the QC flow. While it can be assumed that errors in the source position are negligible, an important task is to check the positioning of the recording geophones and to ensure that the three components are along the desired vertical and horizontal directions. Under the hypothesis of a mechanical isotropic device, a fundamental QC step is to verify that the seismic response of one of the horizontal components is not biased with respect to the other. Indeed, poor receiver coupling to the sea floor affects the accuracy of the recorded data and induces differences between the inline and cross line responses of the horizontal components.
It is common practice in our industry to use the seismic data themselves to control the various parameters of the seismic measurement. Indeed, the redundancy contained in the seismic data is so high that it is sometimes possible to compensate for even severe departures from vector fidelity. This paper describes our understanding of the behavior of the various systems deployed on the sea floor and the methods we have developed and that we routinely use in the first steps of the processing flow.

Source directivity
It is well known that the source arrays used in standard streamer acquisition are in general non isotropic and compensating for a possible asymmetry of its directivity pattern is not an easy task. When such a source is used in 4C operations the possible asymmetry in the directivity pattern affects mostly the acoustic direct arrival. The main consequence is the possible impact on the various steps that involve that arrival. However, a possible asymmetry affects mostly the spatial distribution of the direct arrival.
Deep Ocean Mining - New Application for oil Field and Marine Equipment
Authors: Lecourt Everett J. , Williams Darrell W. 
Published: October 2008

ABSTRACT
The first attempt to mine manganese nodules in a deep water environment was successfully accomplished during the summer of 1970 in the Atlantic Ocean. The conclusion of this prototype test established a significant milestone in man';s attempt to commercially mine natural resources from the ocean floor.
During the thirty day operation on the Blake Plateau, significant tonnages of nodules were pumped through 9 5/8 inch O.D. pipe in 2,500 feet of water. Pipe strain, air-lift pumping data, and ship motion were monitored and recorded by engineer and technicians throughout the operation.
The primary purpose of this paper is to describe some of the operational techniques and equipment used on the which was converted from a type cargo ship. Nearly all of the shipboard equipment was originally developed for the marine or oil industry. - Major components which are described in the paper include:shipdredge pipepipe handling equipmentpumping system andinstrumentation.
The information gathered from the prototype dredging test confirmed that new technology combined with conventional equipment can be used to permit the commercial hydraulic dredging of deep ocean ore deposits.

Introduction
"....the final success of underwater mineral exploitation lies in imaginative, thorough development of conventional engineering techniques rather than in new and highly sophisticated devices." That statement, made by John E. Flipse in his paper in 1969, reference I, expresses the basic philosophy which was followedin the design and construction of the first deep ocean prototype mining vessel - R/V DEEPSEA MINER.
This vessel was used to recover manganese nodules in 2,500 feet of water on the Blake Plateau. Although the nodules in this area lacked sufficient assay value to be mined and processed commercially, the general area provided an excellent proving ground for testing recovery techniques. The remainder of this paper will describe the marine and oil field techniques which contributed to the successful completion of the prototype test.

Prototype Mining System
The prototype mining system utilized a pipe suspended from a ship in 2,500 feet of water. The nodules were entrained in seawater and pumped to the surface through the dredge pipe. A separator on the ship separated the nodules from the water, and the nodules were dropped onto a belt conveyor which dumped them into a storage hopper.
The method of pumping used in the test was an air-lift system. Flow in the pipe is induced by continuous injection of air into the pipe at a depth of 1/3 to 1/2 the depth of the ocean.
Response of Topside Structures to Fires and Explosions: Design Considerations
Authors: Burgan B.A. , Hamdan F.H. 
Published: October 2008

Abstract
The design of topside structures to resist hydrocarbon fires and explosions necessitates consideration of a range of issues not normally addressed by the designer. This paper gives an overview of the key issues that have been studied in several sponsored R&D projects and by the Fire and Blast Information Group (FABIG). The results are presented in a form that is usable by designers. The main areas covered are:Elevated temperature material property design data for use in fire engineeringHigh strain rate material property design data for use in explosion resistant designAnalysis techniques for fire and explosion designDesign methods based on codified rules (i.e. covered by design standards) and advanced techniques

Introduction
The design of North Sea topside structures to resist fire and explosion scenarios received greater prominence since the late 1980's. Numerous joint industry projects were undertaken to better understand the characteristics of hydrocarbon fires and explosions, and the way topside structures respond to such events. In 1992, the Fire and Blast Information Group (FABIG) issued the 'Interim Guidance Notes for the Design and Protection of Topside Structures' (IGN's) [1], the first comprehensive design document to deal with these issues, and this subsequently became the de facto design standard.
Since then, FABIG has issued 7 Technical Notes to supplement the IGN's. These have been distilled from the large number of joint industry projects completed in the 1990's. This work continues with plans now in place for a number of future Technical Notes and new projects identified to generate the background work for other Technical Notes.
This paper draws on the work of FABIG to give an overview of the technical issues that need to be considered by a structural engineer when designing topside structures to resist fires and explosions. In particular, the paper considers the role of advanced and simplified methods, and discusses the input requirements for these methods, especially with respect to appropriate material data.

Design Considerations for Topside Structures Subjected to Fire
The design of topside structures to resist hydrocarbon fires necessitates an understanding of the following issues:Nature of the fire load and how it impacts on the structure (i.e. identification of the nature of the fire, where it will burn, the thermal load generated by the fire and the temperature rise in time of the affected structural members)The performance requirements of the structure (e.g. strength, deformation limits, load shedding, etc.)The response of the structure when subjected to the received heat loading.

Fire Load Characteristics
A number of researchers have studied the nature and evolution of hydrocarbon fires [2,3,4,5,6]. Methods for converting the thermal loading from the fire into a received thermal load acting on the structural members, and subsequently into a time-temperature curve for each member are also available in the literature [7,8] in a form suitable for use in design.
Health and Safety Performance of the Global E&P Industry 2000
Authors: Smith Don 
Published: October 2008

Abstract
The International Association of Oil and Gas Producers (OGP) has been reporting the safety performance on behalf of the upstream oil and gas industry since 1985. Over that period there has been a significant reduction in the fatal accident rate (FAR) and improvements in the lost time injury frequency (LTIF).
In an effort to protect and improve the health of its personnel, the industry has, for the first time, started to collect more detailed occupational illness data from its operations around the world.
This paper presents the results from the year 2000 occupational injury and illness data collection programmes. The main database for this period represents over 1.6 billion hours worked, an increase of 36% compared to the 1999 dataset. Thirty-nine companies contributed safety performance data, from operations in 71 countries. Eight organisations responded to the call for occupational illness information, providing 235 million workhours of data.
It is shown that although there has been an increase in the total number of reported fatalities, the FAR remains similar to previous years due to the increase in the number of working hours reported. The LTIF has continued to show improvements compared to previous years, with the year 2000 data showing the lowest value recorded to date.
The most common types of incident leading to fatalities were vehicle related incidents, and persons being struck by moving or falling objects.
The first year of collecting detailed occupational health data has highlighted a number of problems which will need to be addressed in order to improve on the consistency and volume of this potentially valuable dataset.

Introduction
The International Association of Oil and Gas Producers (OGP) has, since 1985, been collecting and reporting the safety performance on behalf of the upstream oil and gas industry through its annual publication 'Safety Performance of the Global E&P Industry' [1].
This series of reports serves a range of purposes. Firstly, it presents to the widest audience possible how the industry has performed, year on year, on a range of key safety measures. Secondly, it allows E&P organisations to benchmark their performance against that of their peers. Thirdly, it assists the industry to identify areas where it may need to concentrate effort (eg driving related incidents).

Occupational Injury Data.
In the past, the main focus has been on collecting and reporting accurate occupational injury data and statistics. This has, in part, been driven by the relative ease with which injury related data can be collected and analysed, and the industry's, regulators' and public's desire to use such statistics as the primary vehicle for measuring the safety performance of the industry.
Over the years standard definitions of the main parameters which need to be reported have been developed. This has helped to minimise problems associated with organisations reporting injury related data based on a range of definitions.
The Girassol Development: Project Challenges
Authors: Serceau A. , Pelleau R. 
Published: October 2008

Abstract
The Girassol field, offshore Angola, is the largest deepwater subsea development ever brought into production.
This development has been marked by three key dates: discovery (April 1996), sanction (July 1998) and first oil (December 2001).
This paper gives a general description of the Girassol development, outlines the main challenges faced during the project phase and introduces the other papers which are presented on Girassol.

Introduction
The Girassol Field is located 210km northwest of Luanda, the Angolan capital, and about 150km from shore (Fig 1 - Field location).
Girassol was the first discovery made in the prolific Block 17. This was followed by Dalia, Rosa, Lirio, Jasmim, Cravo, Orchidea, etc. The project 's chronology has been marked by three significant dates:
April 1996: Girassol field is discovered on Block 17in deep waters, offshore Angola. This is the first major oil discovery by a consortium led by TotalFinaElf E&P Angola (40%, operator) and its partners - ExxonMobil (20%), BP (16.7%), Statoil (13.3%) and Norsk Hydro (10%). The Block 17 Production Sharing Agreement was signed at the end of 1992 with Sonangol, the Angolan state oil company.
July 1998: The Girassol development project is approved by all parties
December 2001: Less than three and a half years after approval, Girassol comes onstream. By the end of 2001, daily production is 100,000b/d with the production plateau of 200,000b/d to be reached by April 2002.
Girassol is a deepwater giant by many standards:The reservoir, located in 1,400m water depth, is large (10km by 14km). Estimated oil in place is 1,550mmbbls with recoverable reserves put at 725mmbbls. The oil quality of 32°API is close to Brent specifications. Main reservoir and fluid characteristics are given in Fig 2.The Girassol development scheme is based on 39 subsea wells - 23 oil producers, 14 water injectors and two gas injectors. The field will be developed in two phases: the first phase, completed in December 2001, includes 11 wells - eight oil producers, two water injectors and one gas injector. The second phase development is ongoing and will be completed mid-2003 (Fig 3: Field development scheme).The overall investment for the two phases of the Girassol development is US$2.8bn.
In order to bring such a large field onstream in deep waters, it has been necessary to develop and qualify new equipment and to address a number of key issues, such as flow assurance, the need for a flexible subsea layout and reservoir uncertainties.
The Girassol project team had to fulfill three main objectives:First priority was given to technical quality. An extensive qualification program had to be carried out and offshore procedures had to be tested in both shallow water and deepwater tests.Second priority was to closely monitor the development budget and contain the final cost.Third priority was to achieve first oil as early as possible. A very demanding schedule was defined at project sanction with a target start-up date of the end of 2000.
The first and second objectives have been met.