bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Passive Technique for Offshore Navigations and Positioning
Authors: Dennis Arthur R. 
Published: October 2008

Abstract
As part of the continuing effort to improve, offshore navigation/positioning performance and reliability, a new integrated hardware/software configuration has been examined and tested. The system is totally passive so will not interfere with other sensitive on-board instrumentation, and performance equals or exceeds that of any presently-used positioning device in the greater than 100 mile range class. Other advantages include ease of operation and an ability to self-calibrate anywhere at sea. This paper describes the new configuration and presents the results of some sea trials.

Present Limitations Of Medium Range Systems
Precision offshore navigation and positioning beyond the 100 mile or so range from shore stations begins to present physical. instrumental, and logistical problems that increase in severity as range increases. Because offshore operations in many parts of the world are now beginning to extend to these ranges and beyond in almost routine fashion. limitations of presently-used radiopositioning systems are becoming very evident (and often very costly) to users and operators. The author has found that certain problems not usually documented are the most visible to the user. For example:Loss of calibration while far at sea. and the associated re-calibration procedure;The effect or radio frequency (RF) signal interference, either from the nav system or into the system from axternal sources;Operational difficulties, particularly those resulting from the need for highly trained nav system operating personnel (usually scarce) to operate a highly sophisticated instrument;Lack of portability, particularly in the installation of the mobile unit which requires a well-tuned transmitting antenna;.Reduced operating ranges;Cost.
This paper is concerned with percision navigation that can be applied to all facets of offshore work, including critical 3D seismic surveying. Wideband, low-frequency navigation systems such as the U.S. Government-sponsored Loran-C provide for long operating ranges but are difficult to steer with along a precise line because of the inherently high noise levels. Also, Loran-C networks have limited worldwide coverage, with nothing in the Southern Hemisphere. Commercially available Loran is usually restricted in transmitting power so that the operating range is much less than that of Loran-C, often no better than the range of good-quality commercial medium-frequency systems which offer much higher precision.
UHF systems operating in the 400 MHZ range provide extremely high precision but, at ranges in excess of about 150 miles from the shore station, signal propagation characteristics become unpredictable. Therefore most users of these systems restrict operationsto within this range. Also, for the longer ranges very high peak powers must be transmitted, requiring special boosters and even directional antennas, all of which can cause operational difficulties.
Northeast Frigg Subsea Gas Production System
Authors: Duvet Claude E. 
Published: October 2008

Abstract
The North East Frigg (NEF) gas reservoir is a small satellite of the giant Frigg gas field located in the North Sea in 100 meters of water. NEF gas reserves are to be developed using a subsea production system, this being the first major underwater gas production project ever attempted in the North Sea.
The purpose of this paper is to describe the NEF subsea development concept, to explain the ration for its selection and to mention possible applications of this system in the development of other marginal fields.
The NEF subsea production facilities comprises of four major components:–a subsea template which houses and protects six wells and a manifold–a 16" gas line which links the manifold to the Frigg Field Treatment platform (TCP2)–a Field Control Station (FCS) whose main function is to control the subsea equipment–treatment, metering and boosting modules installed on the TCP2 platform to process the 6 million cubic meters per day of NEF gas.
Different development schemes were evaluated during the preliminary selection studies:–conventional fixed steel structure–subsea wells drilled and controlled from a permanent semi submersible platform moored above the wells–subsea wells and manifold remotely controlled from Frigg field–subsea wells remotely controlled from an unmanned articulated column installed close to the well cluster.
The last scheme was selected as being the best optimization in terms of:–Operational safety mainly due to separation of critical functions–Reliability of gas production by extensive use of conventional and tested equipment although assembled in a novel configuration–Investment costs–Potential adaptation of the concept to future developments of marginal fields
To date, detailed engineering of project components is completed, fabrication and drilling are in progress. The production start-up is scheduled in 1984.

Introduction
Recent shortages and uncertainties in oil/gas supplies and the related price increases have transformed some unprofitable, marginal and/or difficult fields into commercial ones. In this context Elf Aquitaine Norge (EAN) and its Partners initiated the NEF development studies for producing a satellite of the giant Frigg gas field. This opportunity combined with the present necessity to develop economically attractive concept for producing marginal fields in a difficult environment led to an unconventional approach.
Preliminary studies began in 1979 with final decision being made mid 1980. Detailed engineering design of the various sub-systems is now completed. Fabrication of NEF components and the drilling of the wells are in progress. Production start up is expected in 1984.
New Safety Valve for Subsea Installations
Authors: Deaton Mike , Brands Klaas W. , Potter Graham 
Published: October 2008

Abstract
A new safety valve was required by North Sea Operators for- their prospective sub-sea completions. The valve would have to combine compatibility with low result subsea wellhead controls with high reliability.
A design team was organized consisting of engineers from an operator and a manufacturer. The project began in 1975. Four years of testing have provided data on the operation of this safety valve. The first two valves were installed in a North Sea Sub Sea Completion in the Fall of 1980.
This paper discusses the design parameters and features of the safety system as well as the performance of the system in tests and In service.

Introduction
In 1975 Shell International Petroleum Maatschappij B. V. (SIPM) in the Hague, Holland was looking for a reliable deep set surface controlled, tubing retrievable, subsurface safety valve (SC-TRSSV) for installation in a dual 3-1/2 inch TFL-completion for a new subsea production wellhead referred to as the Insert Tree project. The attention was focused on Otis who presented at that time their below mud line wellhead (BMW) study which had evolved around the Otis Tubing Hanger Safety System and incorporated SC-TRSSV's.
In the same year Shell Expro, operating in the UK sector of the North Sea, had developed an interest in SC-TRSSV's for their underwater development scheme for the Cormorant field. As a result of this both SIPM and Shell Expro ordered (different) balance line SC-TRSSV's from Otis for in-house testing.
Tests carried out at the E&P laboratory in Holland demonstrated that fail safe closing of either valve under the test conditions, i.e. 3000 ft installation depth and 5,000 psi internal pressure could not be achieved. In addition, the leakage rate after 1000 opening and closing cycles was approximately five times that permitted by the API-14A. These disappointing test results and the pressing need for a reliable safety valve for both the Insert Tree project and the Central Cormorant subsea development scheme, led to the decision to initiate a joint program for the development of a SC-TRSSV which would comply with the requirements for a dual 3-1/2 inch underwater TFL-completion.
Throughout the design phase regular meetings were held between Shell and Otis with continuous Input of ideas from both sides. This finally led to a valve which incorporated both the operators experience and the manufacturers engineering skills. The valve has unique features such as a second balance chamber to facilitate fail safe closing under all circumstances, a lock-out/isolation sleeve, a sliding sleeve which accommodates a TFL back-up valve and a carefully selected sealing arrangement for all static and dynamic seals.
During the extensive testing phase both in Holland and at the Becton TFL test site, some minor modifications proved to be necessary. Finally, after evaluating all test results, the valve was accepted for offshore service.
Two of the requirements for the safety system for the Insert Tree changed with the effect that a single line valve had to be installed.
Improved Synthetic Seismic Trace Generation Using Check Shot Survey Data
Authors: Dohmen Ted E. 
Published: October 2008

Abstract
A review of sonic well log editing using check shot data shows how computer generated synthetics can be made which match the seismic data when the sonic log is otherwise unusable. Comparisons of three sets of data including sonic logs, seismic data, and check shot survey data for two wells from the Louisiana Gulf Coast show up major sources of common errors in both check shot and sonic surveys. A careful examination of the time-depth relationships implied by the integrated sonic log and the check shot data through the creation of a "mismatch" or discrepancy curve defines zones within which corrections can be made to the sonic log in order to compensate for mis-triggering of the tool or even normal errors in fractured or damaged rocks. Also, a good tie between the synthetic traces and the seismic data provides a cross check on the check shot survey. Corrections made to the sonic logs result in geologically consistent ties with the seismic data attaching a new level of confidence to the geophysical interpretation.

Introduction
The sonic log, now almost routinely used in exploration wells is growing in its usefulness to both exploration and production personnel. As seismic data becomes more reliable and higher resolution data is utilized more universally for stratigraphic interpretation, sonic logs perforce become the key in relating geology to the seismic record section. The creation of reliable synthetic seismograms for reflection analysis and correlation is a problem of careful editing and calibration of the sonic tool. Editing procedures are well known, and today's modern borehole compensated tools tend to minimize the number of obvious recording errors. Even so, before the synthetic seismogram is created, the log should be calibrated to match some sort of time-depth control or else small systematic errors in the log will lead to erroneous ties between the litho logy from the well and the reflection data. It is the purpose of this review paper to examine the usefulness of sonic log calibration methods using check shot survey data.
Two wells drilled in Louisiana's Gulf Coast Area show discrepancies between the sonic-Log-derived time-depth relationships and their respective check shot surveys. It is especially important in this and other plays to know the depths not only to the objective, but also, to several geologic zones above the objective which dictate the planning of the drilling program. The obligation rests with the geophysicist to try to infer these depths from the seismic data. The first well, which I shall call "Well A" has a sonic log which exhibits a very large error due to undetected tool problems encountered during recording of the log. The second well, "Well B" exhibits some subtle discrepancies attributable to errors in the check shot survey interpretation. In both cases, a detailed examination of the discrepancy between the two types of data for each well has allowed the determination of the source of the errors and thereby, a reason for correcting them.
Environmental Protection in the Beatrice Field Development
Authors: Hay James Taylor Cantlay , Hay Herbert Douglas , Debnam Gordon Frank 
Published: October 2008

ABSTRACT
The development of the Beatrice field in the Inner Moray Firth area of the UK North Sea has presented particular problems in the area of environmental protection. Because the field lies only 12 miles from a totally unspoiled coastline of very great scenic beauty and environmental quality, it was necessary, before field development approval could be obtained, to convince central government, local authorities and various nature preservation bodies that an environmental protection plan could be developed.
The plan, which covered the offshore field, pipeline and onshore terminal, consisted essentially of three main elements. Firstly, an environmental impact analysis Was commissioned, to be carried out by An independent specialist consultant, which Was subsequently progressed into a long Term monitoring programmed.
Secondly, a plan was drawn up to deal with the prevention and control of spillages, both offshore and onshore. This presented particular problems due to the proximity to the shore and the waxy nature of Beatrice crude which made the use of conventional dispersant methods impracticable, and required the development of innovative techniques.
Finally, a series of technical discussions took place with local and central government authorities, followed by a series of presentations at public meetings. It was thereby possible to not only gain the necessary approval of the authorities, but also to establish the confidence of the local population and the various environmental and conservation organizations.
The Beatrice Pollution Control Plan is the first developed for a near shore oil field in the UK. As such it provides guidelines for dealing with similar developments in future.

INTRODUCTION
The Beatrice field development with its offshore installation, pipeline, terminal and tanker loading jetty is located in the Inner Moray Firth area of the UK. (Figure 1). The field is in Block 11/30 of the UK Continental Shelf and is approximately 12 miles from the nearest point of land.
The field is being developed by a Consortium for which the British National Oil Corporation is Operator. The participants in the Consortium holding interests in the field are as follows:-British National Oil Corporation- 28%Kerr McGee Oil (UK) Ltd.,- 25%Deminex UK Oil and Gas Ltd. - 22%BP Petroleum Development Ltd.- 15%Hunt Oil (UK) Ltd. - 10%
The discovery well for the field was drilled in 1976 and production commenced late 1981. Beatrice crude has a high wax content with a pour point of 20° C, and requires treatment to maintain pump ability. Special contingency equipment has had to be developed for the event of spillage.
Because of the special handling problems of the crude, the first development plan proposed for the field was based on loading direct to tankers in the field. The plan encountered stiff opposition from environmentalists and fishermen, since it was considered to be prone to spillages which could quickly land onshore and would also be detrimental to fishing interests.
Risk Analysis Applied to Offshore Platforms During the Unpiled Installation Phase
Authors: Kriger Glenn , Piermattei Earl , White J.D. , King R.W. 
Published: October 2008

ABSTRACT
Risk analysis applied to the design of fixed offshore platforms during the unpiled installation phase is described. This procedure for analysis and design of platform stability assesses risk for a selected sequence of installation activities and provides a logical method for safe, economical design based on the uncertainty of design criteria.

INTRODUCTION
During the installation of a fixed offshore platform, from the time of upending onto the seabed until completion of the foundation piling, the unpiled platform behaves as a gravity structure. The platform weight and variable environmental forces may cause settlement, sliding, and motions that hinder pile installation. Evaluation of the platform's safety during this phase of installation is called on-bottom stability analysis.
Traditional deterministic methods for assessment of on-bottom stability are not considered satisfactory in many cases. These design methods assume a large wave height coupled with low soil strength, resulting in excessive foundation design. They do not take into account the variable seabed soil strength, uncertain wave heights during the relatively short unpiled period, or changing platform configuration during installation. Standard codes of practice offer little-guidance for assessing platform safety under these variable conditions, and analysis techniques developed and used in well understood environments may not be applicable to new situations.
The risk analysis method differs from traditional design methods because it considers uncertainty in soil strength and wave height in addition to variable unpiled exposure time and platform configuration. Risk analysis balances economical design with acceptable levels of risk by accounting for these conditions. This design method should be of interest to platform owners, structural design and soil mechanics engineers, installation contractors, and insurance surveyors because it provides this balance of economy and safety.
This paper outlines the risk analysis method for on-bottom stability analysis of a platform during the unpiled installation phase. On-bottom stability analysis begins with a study of potential modes of failure. Next, installation activities are investigated that are required to complete the piled foundation to a stage in which the platform is safe. The sequence of these activities affects foundation forces and therefore the foundation resistance required. An economic value analysis considers the costs of different foundation configurations and their associated risk levels. Finally, the risk analysis uses analytical methods to assess system reliability based on the uncertainty of design criteria.

MODES OF FAILURE
In order to perform an on-bottom stability design, all potential modes of failure must first be identified. The consequence of each failure mode must be studied in terms of recoverable and no recoverable damage.
Self Installable: Floating Production Facility Requires Only Light Support Craft
Authors: Hummelinck M.G. Wagenaar , Davison Chris 
Published: October 2008

ABSTRACT
Installation was completed successfully at the Tazerka field offshore Tunisia of an integrated multi well floating production, storage and offloading (FPSO) facility comprising a converted 210 000 dwt tanker and a single anchor leg storage (SALS) mooring and fluid transfer system.
The requirement to install this FPSO in 140 metres of water without heavy construction barges necessitated active participation by the installation engineers very early in the system design stages.
Installation commenced in March, 1982, with the tow of the 140m riser, floating horizontally, from its fabrication yard in Dunkirk to Malta where it was connected by a universal joint to the anchor base. The base/riser combination was towed to deep water and upended by ballasting after which it was towed vertically to Tazerka. Once in position, iron ore was added to the base followed by connection of base/riser jumper hoses for production and well control.
The second installation phase began in October, 1982, with the tow of the tanker/SALS yoke combination from southern France to Tazerka. Hookup between the riser top and yoke was made using a wire rope from the riser top over the yoke by which the tanker pulled itself to the riser. Final installation involved removal of sea fastenings from the 250 ton manifold chamber and securing it to the riser top using a shear leg on the SALS yoke.
In effect, this FPSO facility was self-installable in that no heavy construction barges were required; only relatively low cost vessels were needed to tow the various components to the site and to assist with final hookup of the SALS mooring and the fluid transfer system.
There is good reason to believe that the installation techniques developed for the Tazerka FPSO can be applied to even larger systems in still deeper and rougher waters without requiring heavy construction barges.
This paper presents the design and step-bystep installation procedures developed to ensure safe, reliable and speedy installation without using heavy construction equipment.

INTRODUCTION
The Tazerka field was discovered by Shell Tunirex operating for a joint venture with AGIP of Italy in July, 1979. It is situated some 56 km offshore Tunisia (Fig. 1) in water depths of 140-300m in the Hammamet Grands Fonds permit. Recoverable reserves in the field are estimated at 10 million barrels making it a relatively small development. The Tazerka joint venture now comprises Shell Tunirex (40%) as operator, AGIP (40%) and the Entreprise Tunisienne d'Activites Petrolieres (ETAP, 20%).
Shell Internationale Petroleum Maatschappij B. V. (S. I. P .M.) was appointed by Shell Tunirex to act as Engineer on behalf of the Operator throughout the project and SBl\l Inc. was awarded contracts for design, construction and installation of the mooring and SALS fluid transfer systems.

SYSTEM DESCRIPTION
The Tazerka field integrated floating production, storage and offloading facility comprises the following principal components and subsystems (Fig. 2).