bluuebunny/crossref_metadata_2025 huggingface dataset:
A Retrospective Assessment Of Fatigue Damage Suffered By West Sole Platform W. E.
Authors: Cannell Christopher , Starsmore Neil
Published: October 2008

In September 1978, at the end of its 12-year operational life, the platform WE was removed from the West Sole field in the North Sea for detailed examination and further research investigation.

This paper presents the results of a retrospective spectral fatigue analysis carried out on the platform, with the aim of assessing the extent of the fatigue damage incurred during its exposure to the North Sea environment.

The structural model is constructed using results from dimensional surveys, observed marine growth and actual foundation conditions. Environmental data recorded on the platform is used as a basis for wind and wave loading calculations.

Stress response spectra are calculated for eight inspection points at the end of each structural element for each sea state considered. The total damage due to all sea states is accumulated using Miner's Rule and appropriate stress concentration factors and SN-curves.

A comparison is made between the fatigue lives obtained using unidirectional data recorded on the platform and directional data obtained from other sources.

The effect on fatigue lives of some joints due to variation of some important parameters is investigated.

When completed, the study will allow an objective assessment of the viability of the latest methods used by designers to predict the fatigue lives of offshore steel structures.

INTRODUCTION

Fatigue is responsible for the failure of a great many engineering structures, and is not just a peculiarity given to offshore oil and gas production platforms. The main features of fatigue damage are:cyclic loadingtime

These can be found in a variety of engineering environments, including offshore oil platforms, which are subject to large amplitude variations in loading, due to wave action, and are usually deployed for a great length of time. Combined with a degradation of the ability of steel to withstand fatigue loads, this means that fatigue life prediction is of primary interest to the offshore designer.

For shallow water production platforms, the primary design loads are given by an extreme static load, as represented by the "design wave". This was, for example, the 100 year wave, arrived at by the extrapolation of climatic field data, and which is then applied to the structure to give the maximum horizontal shear force/overturning moment at the mud line. Any prediction of fatigue life was then based upon the design load, but scaled to fit the sea states anticipated for the service life.

The fatigue analysis was deliberately kept simple, since it was considered that during the service life of the structure the chances of failure due to overload were greater than the chances of failure due to fatigue.

North Sea structures had, to a large extent, inherited this design procedure from the Gulf of Mexico, and such was the case for the platforms deployed on BP's West Sole gas fields Indeed, platform WE was the first platform to be installed in the North Sea for the exploitation of the natural reserves.
Fatigue Strength Of Overlapping Tubular N-Joints
Authors: Ohtake Fumio , Sakamoto Suguru , Nakazato Takuzo , Minoshima Tsugio
Published: October 2008

The main objective of this study is to obtain the quantitative guidance for the fatigue design of saddle type tubular joints with overlapping braces on the chord surface. Systematically planned sixty-one specimens were totally tested under the completely reversed sine wave axial load (R =-1). All of them were isolated N-joints with a chord of 318.5mm in outer diameter. The specimens were classified into 13 groups in accordance with the parameters D/T, d/D, T/t and g/d, where D and T are outer diameter and wall thickness of the chord, d and t are outer diameter and wall thickness of the braces and g is gap or lap length of the braces on the chord surface, and another group of joints with in-plane gusset plate reinforcement. Materials used were mild steel with the specified ultimate strength of ?u ?402 N/mm2 and high tensile strength steel with ?u ? 784 N/mm2 (equivalent of ASTM A514 Grade F steel). The cycle range repeated for each group was N = 103 ~ 2 × 106.

Characteristics of the test results were :The joints with a gusset plate reinforcement are inferior to those with a small positive gap length in the fatigue strength.By overlapping the braces on the chord surface, a fatigue life to failure of the joints is increased about 10 times as long as that of conventional gap-joints or joints with a gusset plate.The use of a high tensile strength steel in overlapping-joints has adequate effects on longevities of the joint fatigue life.

INTRODUCTION

Steel tubular structures in offshore are generally characterized by the direct welding of brace members upon the chord wall. In such connections, the stress concentration is so severe that the static and dynamic strength of the joints is much decreased. The problem is mainly caused by the matter that the axial forces of the braces directly act on the chord wall in the out-of-plane direction. In general, because the compressive and tensional forces act from the braces upon the chord wall and the sum of the vertical component forces to the chord is not so large, the joint strength is expected to be remarkably improved by direct cancellation of the vertical component forces among the braces, without passing through the chord wall.

Overlapping of the braces is one of the methods for improving the joint strength by the above effect. It is known that those joints, that is, overlapping-joints give their connections sufficient efficiencies under the statical load. The empirical formulae for the prediction of static strength of these joints have already been established on the basis of numbers of previous test results.1,2

While it is also expected that the use of these joints may increase the fatigue strength of tubular structures, enough fatigue tests for the joint have not been conducted. The researches on the fatigue strength of these joints have been deferred by the technical difficulty of the edge preparation of the braces for their complicated cutting lines.
Dynamic Analysis Models of the Tension Leg Platform
Authors: Jefferys E. Richard , Patel Minoo H.
Published: October 2008

Tension leg platf9rms are designed with natural periods of oscillation which are well separated from the dominant wave excitation frequencies so that displacements remain acceptably small even in severe weather conditions. However, the results presented in this paper show that the tensioned tethers can resonate at periods close to those of wave excitation if the platform is deployed in deep water where its economic advantages are held to be greatest. Analysis which ignores the tether dynamics gives good estimates of the wave induced motion amplitudes of the platform but can be seriously in error when predicting the dynamic tether stresses. An additional uncertainty is associated with interactions between the varying longitudinal tether tensions and lateral platform dynamics which can lead to a Mathieu type of instability. A simple energy balance approach is presented in this paper to quantify the effects of linear and square law damping on the severity of this instability. It is demonstrated that the effect of nonlinear square law damping is to impose an upper bound on the otherwise unstable oscillations. An algebraic expression for this upper bound is derived by consideration of an extreme 'worst case' situation.

Introduction

The use of a tensioned leg platform(TLP) as an alternative to offshore oil production from fixed or catenary moored structures is receiving serious attention within the offshore industry. Research has advanced to the stage where plans have been announced to produce oil from a north sea field using a tension leg design.

A TLP possesses a combination of desirable characteristics as an offshore work platform. The absence of a fixed rigid structure from sea surfaceto sea bed, coupled with excellent station keeping characteristics, satisfy the two important demands of economyand practicality that are made on any offshore production system. A TLP exhibits wave induced heave roll and pitch motions which are much smaller than those of a conventional floating structure. Larger off station surge and sway motions can, however, result due to the low restoring stiffnesses in these directions. This feature serves as a positive advantage since horizontal wave loads are then not fully reacted by the surface platform.

Despite these obvious advantages, the compliant nature of a TLP does raise uncertainties regarding the detailed platform dynamics particularly for deep water applications. Field and Flogeland suggest a number of problem areas which have not yet been adequately resolved. Two of these are particularly important for the TLP and are concerned with the influence of the detailed dynamics of a realistic tether system on platform motions and tether stresses and the limiting effects of fluid damping on the size and occurrence of subharmonic resonance or instabilities.
The State Of Hawaii Manganese Nodule Program:Infrastructure And Other Studies
Authors: Keith Kent M. , Jenkins Raymond W.
Published: October 2008

The State of Hawaii is the only local jurisdiction in the United States with a Manganese Nodule Program. The goal of the Program is to attract to Hawaii a manganese nodule processing industry which is environmentally sound, socially acceptable, and economically beneficial to the people of Hawaii.. Program elements include industry interaction, public information, and impact assessment. The infrastructure study is designed to assess industry needs, the infrastructure available in Hawaii, and gaps which may need to be filled. Two manganese nodule mining consortia have already rated Hawaii as a prime contender as a processing site.

A Brief History Of The Program

The State of Hawaii Department of Planning and Economic Development (DPED) and the University of Hawaii have been interested in manganese nodules for the past ten years. One example of early intergovernmental cooperation was the convocation of a workshop on Manganese Nodule Deposits in the Pacific, ll held in Honolulu in October 1972.1 This workshop was sponsored by the DPED, the Hawaii Institute of Geophysics, the State Marine Affairs Coordinator, and the Office of the International Decade of Ocean Exploration.

The potential of a manganese nodule industry was pointed out in Hawaii and the Sea-1974, published by the DPED.2 In that report, the Governor's Advisory Committee on Science and Technology recommended that the DPED write a report which would look at the total mining industry system, investigate and evaluate alternative processes and sites which might be used by onshore manganese nodule processing plants, and discuss plans and processes with the major mining companies.

In 1975 the Legislature provided funding to begin 'a manganese nodule program designed to assess the potential of a nodule processing industry in Hawaii. A study group of consultants from the University of Hawaii was hired and research began in March, 1977. In September, 1977, while research was in progress, a representative of Kennecott Copper Corporation visited Hawaii and at a press conference rated the Island of Hawaii as a prime contender for a processing site.3 The study group report, The Feasibility and Potential Impact of Manganese Nodule Processing in Hawaii,4 was published in February, 1978.

In the Spring of 1978, representatives of Ocean Minerals Company (OMCO) visited the State, and in September announced that OMCO would build an Equipment Test Unit (ETU) at Campbell Industrial Park on Oahu. The plant was estimated to cost $4 million, and was expected to employ a dozen people for three to five years, processing 50 dry-weight metric tons of nodules per day at an annual operating cost of $1 million. The ETU was to be smaller than a pilot plant, since it was designed only to test the processing equipment. Plans for construction of this plant have been delayed indefinitely, due to the uncertainty of the international law of the sea. In the interim, OMCO has continued to refine the processing methodology which would be tested at an ETU.
Geotechnical Analysis Of A Submarine Slump, Eureka, California
Authors: Lee Homa J. , Edwards Brian D. , Field Michael E.
Published: October 2008

A large submarine slump covers more than 150 km2 of a gentle (1 W) slope offshore of Eureka, Calif. We have conducted a detailed geologic and geotechnical investigation of the slump and the surrounding area to delineate the geometry of the slump, determine its cause, and quantitatively evaluate the sediment properties that led to the failure. Our study included an effort to test procedures for using short-core samples in such an evaluation. Cyclic and static triaxial and one-dimensional consolidationtests were performed on gravity-core samples from both within and outside the slump; all samples showed some degree of overconsolidation. We used a normalizedstrength- parameter approach to estimate the strength at the failure surface below the level of sampling. A stability analysis based on a pseudo static infinite-slope model shows the slump probably to be earthquake induced. This analysis also gave values of the sedimentparameters leading to failure at the slump site and to stability at surrounding sites. Owing to the complex variation in sediment properties, subtle changes in properties may determine the stability or failure of thesediment mass.

Introduction

Slumping (defined as rotational movement along a discrete failure surface) is common to many continental margins of the world and can be an important mechanism of downslope sediment transport (Cook and others, 1981). With the expanded economic exploitation of offshore areas, mass transport of sediment by slumping and other means has become an important consideration in engineering design. Because of the hazard that such mass transport poses to engineering structures, a need exists both for identification of active or potential sediment failures and for quantitative assessment of the potential formovement.

Both a geologic and geotechnical (soil mechanics) approach to the study of submarine slumps is important for complete assessment. Interpretive sub bottom acoustic profiling and side-scan sonography are required for identification of zones of past and present instability, whereas measurements of sediment strength and other characteristics are needed to diagnose failure mechanisms and stability factors. From a combined approach, an understanding of submarine mass transport can be obtained.

Studies conducted in 1977 and 1978 by the U.s. Geological Survey identified several large areas of unstable sediment, including the one discussed herein, on the continental margin off northern California (Field and others, 1980). In 1979, a combined geologicgeotechnica 1 a na lysis of a large slump a nd the surrounding sea-floor west of Eureka, Calif. was conducted. The study was designed to evaluate the geometry of the slump, the mechanism of failure, and the relative stability of adjacent areas.
Wind Overturning Effects Obtained From Wind Tunnel Tests With Various Semisubmersible Models
Authors: Bjerregaard Egon T.D. , Sorensen Erik G.
Published: October 2008

General trends concerning the wind overturning forces and moments on semisubmersibles are drawn from the results of wind tunnel tests carried out with a number of different semisubmersibles, each in variousloading conditions.

In (1) it was demonstrated thaL for beam wind conditions large discrepances exists between the results from empirical calculation methods as outlined in rules and regulations and results obtained from wind tunnel tests. It was assumed that lift forces were the main reason for this lack of correlation.

The present paper deals primarily with combined heel/pitch for the most cirtical wind direction close to a diagonal direction. Some typical results obtained from wind tunnel tests are presented and the importance of the lift components is demonstrated.

Introduction

IE has now become a normal practice for many designers and owners of semisubmersibles to carry out wind tunnel tests in order to obtain as exact knowledge as possible to thawind forces and moments that have to be encountered.

It is realized that the empirical calculation methods outlined in rules and regulations cannot possibly cover every conceivable layout without leading to overpessimistic .windforces for many designs. Too conservative estimates of windforces will result in a number of consequences all of which will be on the detrimental side of the cost benefit of the semisubmersible. Tne windforces are important for decisions concerning:

Anchoring systems design. Dynamic positioning strategy. Intact and damaged stability calculations. Deck load carrying capacity In the various codes of practice for calculation of wind effects it is a common method to prescribe drag coefficients in non-dimensional form for different geometrical shapes. The wind force at a given wind velocity is then proportional to the wind speed squared, the shape coefficient and the projected area. The wind moment is the product of the wind force and the arm between the centre ofaction of the wind force and the centre of reaction. This method does not include lift forces. It could be characterized as a two-dimensional way of treating the problem.

Semisubmersibles are, however, three-dimensional bodies typically with front and side areas of almost equal size, and with a large extension in the wind direction. The wind-flow over the body will therefore create a pressure distribution resulting in both a drag and a lift force. Figure 1 illustrates how this flow pattern might look, and where pressure and suction are likely to occur.

The only way of obtaining exact knowledge of the sizes of the lift and drag forces and the resulting moments is by carrying out wind tunnel testswith a carefully scaled model of the semisubmersible. During the last 2-3 years a number of wind tunnel tests have been performed with various designs for different clients at out laboratory. For this presentation some typical results and common trends concerning the wind effects have been extracted from the wind tunnel test results.
A New Passive Technique for Offshore Navigations and Positioning
Authors: Dennis Arthur R.
Published: October 2008

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

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

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

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

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

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

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).
The Murchison Cathodic Protection System
Authors: Levings E.A. , Finnegan J.E. , McKie W.M. , Strønmen R.D.
Published: October 2008

The Cathodic Protection System installed on the Murchison Platform sets new standards for the operation of cathodic protection in the arduous conditions of the North Sea.

It has demonstrated its effectiveness and flexibility since being commissioned in November 1980. Extensive data has been accumulated from the system monitors, comprising zinc reference potentials, current outputs from impressed and monitored sacrificial anodes, and from underwater surveys of potential and current density.

An improved understanding of the dynamics of cathodic protection systems can only be achieved through analysis of data from actual structures. The nature of the Murchison cathodic protection data has enabled computer modelling1 of characteristic current density and potential optimum protection level is projected from this model and the hybrid system adjusted to satisfy the demands of the structure.

This paper briefly describes the system, the stages to successful operation and indicates the developments with which this unique system has enhanced our understanding of cathodic protection parameters.

INTRODUCTION

The Murchison jacket was to be the largest ever launched by barge when in September 1979 the limited launch barge capacity required a weight saving alternative to the proposed 1200 Tonnes of sacrificial aluminium anodes. Various options were considered 2 and the system adopted for Murchison is an unique hybrid.

The main impressed current system is designed to automatically maintain potentials within set limits using numerous impressed current anodes which are mounted directly on the structure and controlled in small groups by nearby reference cells. A sacrificial system designed to provide protection to sensitive areas during period when the impressed system is switched off is also installed. Sacrificial anodes modified to monitor current output are located strategically on the submerged structure.

The system was designed to comply with the cathodic protection design criteria available in 1976/1977, i.e. that a current density of 130mA/m2 is necessary to ensure adequate initial polarisation of the structure.

Basic parameters of the design comprise:-A sacrificial system to provide limited levels of protection at sensitive areas for the period between float out (Sept. 179) and commissioning (Nov. 180) and when de-energisation of the impressed current system is necessary.An adequate monitoring system to enable effective control and monitoring of the system.An automatically controlled impressed current system using suitable anodes located directly on the structure.Robust design of the underwater parts of the system to ensure maximum integrity for the life of the platform, together with facilities for retrofitting of additional anodes if required.

The main parts of the system equipment are summarised in Table 1, and are more fully described elsewhere.2,3.
Satellite Tree Subsea Completions Permit Marginal Reserves Production Offshore East Kalimantan, Indonesia
Authors: Bunnell R.L. , Hawkins J.G.
Published: October 2008

The hydrocarbon-bearing sands in the fields offshore East Kalimantan were deposited in a de 1taic environment and are complicated by faulting. This faulting results in small accumulations which cannot be economically exploited by conventional means.

Three of these accumulations had been discovered in the Attaka Field in water depths of 160-190 feet. Even though the weather conditions are mild, conventiona1 platforms were ru1ed out on economic grounds. An alternate method employing subsea completions was found to be economically Viable. This subsea system is characterized by its "off-the shelf" configuration and simplicity. To reduce the possibility of required well workovers, the wells are single string, gravel packed completions.

This project, then, is an example of a subsea completion system being chosen for marginal reserve deve1opment based on economic grounds. Additionally, these are the first subsea completions in Indonesia and yielded much information for use in designing, scheduling, and costing similar installations. The wells were all previously drilled and suspended exploratory wells, and the completion operations were performed from a floating vessel.

INTRODUCTION

The Attaka Field is located in the Makassar Straits, 12 miles offshore from Tanjung Santan, East Kalimantan, Indonesia in ±200 feet of water (see Figure 1). Union Oil Company of Indonesia is the Operator of the Attaka Field in a unit with Indonesian Petroleum Ltd. (Inpex). Each company has a separate production sharing contract with Pertamina, the Indonesian State Oil Company.

The Attaka Field structure is a symmetrical anticline trending north 10° west with gentle 10° to 200 flank dips. The main Attaka sand reservoirs were deposited in a de1ta ic environment and range in age from Middle Miocene to Pleistocene. The structure is intersected by several sub parallel normal faults trending northwest-southeast with displacement varying from 100 to 900 feet. Field reserves are attributed to twenty-two separate sands found between 2800 and 7600 feet. Porosities of the sands range from 20 to 35 percent with permeabilities as high as five darcies. Most reservoirs have a gas cap, are saturated, and display varying degrees of natural water drive. The oil has a low sulfur content, and its gravity varies with depth between 35° and 43° API.

Discovery of the Attaka Field occurred in August 1970, and primary development was completed in September 1973 after the drilling and completion of 52 wells from six wellhead platforms. The wells were completed, for the most part, with dual strings and from three to five packer intervals. Between 1973 and the present, 18 additional platform wells have been drilled and completed and two more platforms installed (see Figure 2). Production from the Attaka Field peaked at 117,000 barrels of oil per day in November 1977 and now averages 62,000 barrels of oil per day.