bluuebunny/crossref_metadata_2025 huggingface dataset:
Modelling The North Sea Through The North European Storm Study
Authors: Peters D.J. , Shaw C.J. , Grant C.K. , Heideman J.C. , Szabo D.
Published: October 2008

The paper describes the development of a hindcast database of wind, wave and current parameters for the North Sea and Eastern Atlantic ocean. The study, which was a joint industry project funded by u group of nine oil companies and two government agencies, was initiated to enable consistent metocean criteria and operational statistics to be derived for offshore areas of the UK, Norway anti the Netherlands.

The wind, wave and current modeling work, which was carried out by a consortium office European technical institutes is described. In particular, a description is given of the careful development of the wind fields during the 2S-winter period of the study especially during the severe winter and summer storms. The relatively large amount of measured field data which is available for the North Sea enabled detailed comparisons to be made with modeled data und highlighted the cure which needs to be taken when comparing the two and in calibrating verifying models.

An aspect of the study which is probably unique is the formation of a follow-on study which adds new storms to the database as they occur thereby enabling questions concerning the influence of some of the severe recent storms to be readily answered when preparing design criteria for certification purposes.

The NESS study is an application of new technology to a mature area. Results of the study have been included in the establishment of design wind, wave, and current criteria for North Sea installations. In addition the database is proving to be u valuable source for assessing the reliability of existing structures and for improving loud calculations on structures by enabling the uncertainty und variability in environmental conditions to be quantified.

INTRODUCTION

The North European Storm Study (NESS) was initiated in order to produce a high quality hindcast database of winds, waves, storm surges and depth-integrated currents for the North European continental shelf (Figure 1.1). The project was funded by eleven Participants (nine oil companies, and two government departments) and the work was carried out by meteorological, and oceanographic institutes in five European countries.

To be successful a major hindcast project needs to have certain attributes. First amongst these is the technical expertise of the members of the modeling institutes, and the models which they will be using. Second is the availability of high quality measurements {it fixed locations with which the models can be calibrated, and verified. Furthermore, there needs to be a sufficient number of motivated participants to manage and carry through the project as well :is to contribute on technical issues as they arise. The project took more than five years to complete at a cost of over £2. 1 million, and has resulted in ii major asset to the industry from which both significant cost-savings, and improvements to the safety of operation scan be expected for many years.
Exploitation Of Marine Current Energy
Authors: Garbuglia Emanuele , Rosa Alberto Dana , Berti Dario
Published: October 2008

This paper describes the results of a feasibility study regarding the exploitation of marine currents in the Strait of Messina (Italy). The high kinetic energy contents of these currents suggest the development of some exploitation system. The technical solution, proposed in the study, consists of seabed installed vertical axis turbines, which are able to optimize energy extraction. The work performed at this stage included a basic design of the system and a preliminary evaluation of the Environmental Impact. A costs/benefits evaluation showed that electricity produced by the proposed system is competitive with that based on other energy sources, conventional ones but mostly renewable ones. Moreover fresh water, considered in alternative to electricity production, could be produced at costs comparable with present supplies by shuttle tankers.

INTRODUCTION

Marine currents represent a large renewable energy resource and can give a significant contribution to fulfilling energy demand, with emphasis put on local supplies. Among the ocean and renewable energy resources marine currents have certainly not been given enough consideration by researchers and energy authorities. The reason can probably be found in the fully marine characteristic of the systems suitable for exploiting marine currents, if compared with either OTEC, wave or tidal energy systems which are essentially land based. As in all the other renewable and non-conventional energy resources, so the energy extracted from marine currents can hardly exceed a few percent of the global energy consumption, even if in several cases it can play an important role in counteracting energy shortage while coping with environmental constraints in coastal areas or isles, by integrating or substituting energy systems based on conventional resources, like oil, gas or coal.

The technical interest of the study stems from the high kinetic energy content of marine currents in the Messina Strait (South of Italy) and from a socio economic context that suggests following the logic of local development, The study, even if targeted at a particular application, is aimed at proposing general guidelines and technological solutions for dealing with analogous situations of exploiting marine currents. The size of the proposed hydro-generator (1 MW electric) and the modular system approach make this solution suitable in various contexts,

THE SITE

Geography

The Messina Strait (fig. 1) is a small sea channel about 30 km long with a minimal width of 3200 m, that separates the Italian mainland from the island of Sicily, connecting the Ionian and Tyrrhenian Seas. It presents a variable bottom profile with a depth of up to 1500 m. The profile is characterized by the presence of a transversal sill, in the northern part of the strait which is also the narrowest. In correspondence of this sill the depth rapidly reaches the minimum of about 80 m over a length of about 7 km. This point constitutes a net separation between the two seas and a "bottle neck" for the water flow.
Design Provisions For Offshore Grouted Construction
Authors: Seie Arne , Skjolde Monica
Published: October 2008

A data base containing 750 the ultimate strength test results on" of grouted connections has been assessed in order to provide improved design guidance. The test data have been screened in order to obtain an assessment of available design equations. The data have also been systematically studied to identify new trends discernible from this large data base which has not previously been available as an entity. Supplementary tests have been performed on specimens with high h/s ratios and to obtain data on grout to steel interface friction.

The screened test data have finally been used in a calibration study on the design formulations used in three different codes. - API RP 2A, DNV and D. En. (U. K.). DNV's structural reliability programme "PROBAN" has been used to estimate safety factors, load factors and material factors required to achieve the same target reliability as aimed for in the new API RP 2A LRFD code. Significant differences between the safety levels in the D. En. Guidance and those entrenched in the API and the DNV codes are indicated. The study indicates that the reliability levels entrenched in the API and DNV codes are in line with those adopted in structural design in general. Sensitivity studies have been performed to support the reliability calculations.

Variations in the design equations as well as the adopted safety margins give rise to very large differences in required connection lengths. The more conservative requirements may lead to as much as a 200 % increase in connection lengths.

FAILURE MODES OF GROUTED CONNECTIONS

The failure modes observed to occur in grouted connections depend on whether shear keys are present and their size and spacing:

PLAIN GROUTED CONNECTIONS have no shear keys. In this case failure occurs by slipping along the interface between the pile and the grout. On dissection some tensile cracks may be observed in the grout. These are, however, of a secondary nature and principally due to shrinkage and not relevant to the failure. All relative displacement takes place at the pile surface. The connection behaves as two rigid elastic bodies. It can be observed that tensile hoop stresses are set up in the sleeve and compressive hoop stresses in the pile. This due to the wedging action caused by the uneven surface of rolled steel tubulars. Tests performed by DNV using tubulars which have been turned down in a lathe to produce a uniform surface show a radical reduction in load carrying capacity. % strength of plain pile connections is, therefore, dependant on the magnitude of the wall surface unevenness as well as on the hoop stiff nesses of the pile and sleeve. This can be expressed by the sum of the thickness to diameter ratios of the tubulars and will determine the radial stress set up by the wedging action and, thus, the inteface friction force that will be mobilized. This is developed in detail in reference /1/.
An Update On Allowable Fatigue Stresses In Api Rp2A
Authors: Luyties W.H.
Published: October 2008

The results of a recalibration of the simplified fatigue design procedure for tubular joints using the new design wave hydrodynamic criteria in the 20th edition of API RP2A are presented. The four structures used in the original calibration study are examined with the new criteria and revised curves of allowable peak hotspot stress for the Gulf of Mexico are derived. As a first step in potentially expanding the simplified design procedure to other oceanographic climates, results of a calibration study are presented for a structure designed for a wave climate outside the Gulf of Mexico. Also, to provide justification for new API requirements for minimum structures, calibration results are presented for a self-standing caisson structure in the Gulf of Mexico.

INTRODUCTION

The 17th edition of API RP2A (reference 1) provided curves of allowable hotspot stress versus water depth to be used in simplified design of tubular joints for fatigue. Given a platform water depth, design fatigue life, location of member within the structure, and S-N curve, an engineer could determine the appropriate allowable hotspot stress. This allowable stress would be used in conjunction with the peak hotspot stress from the fatigue design wave to design joints and would result in generally conservative fatigue lives when compared to those determined from a full detailed fatigue analysis. The fatigue design wave was defined as the API reference level wave applied with tide and marine growth, but with no gravity load effects, wind, or current.

A key factor in the accuracy of the simplified design method is the magnitude of wave force generated by the fatigue design wave. In the 20th edition of API RP2A (reference 2) the design wave force criteria were upgraded to incorporate new data on wave heights, currents, drag coefficients, current blockage, and wave directionality. In general, the entire "recipe" used to define the design wave changed. It was recognized that such a change might alter the relationship between design wave and allowable hotspot stress. Four courses of action were available to API:do nothing and accept an unknown effect on simplified design,leave the 17th edition reference wave height in the new edition as the fatigue design wave,abandon the simplified method within RP2A, orrepeat the calibration effort to determine new allowable hotspot stress curves to use with the new wave recipe.

Option 1 was deemed unacceptable. Option 2 would result in two design wave criteria within the same document and was judged to be undesirable and potentially confusing. Option 3 would require detailed fatigue analyses of all structures, which was felt to be an unnecessary added cost and effort. Therefore, in 1991 a task group was formed to recalibrate the simplified fatigue method and propose new allowable hotspot stress curves for inclusion in the 20th edition of API RP2A
Long Buoyant Flexible Pile Frames for Support of Deepwater Offshore Platforms
Authors: Copple R.W.
Published: October 2008

This paper is about Long Buoyant Flexible Pile Frames for support of deep-water offshore platforms. These Long Buoyant Flexible Pile Frame structures combine elements of bottom-founded and floating systems. They consist of one or more piles (legs) rigidly connected to bending members (trusses) at the sea floor, and also near their upper ends below or above the water surface. The piles are large-diameter steel cylinders. There is a watertight bulkhead in each pile with the pile open to water below the bulkhead and open to the atmosphere above the bulkhead. The buoyancy of the piles supports the structure plus the payload. Overturning moment caused by wind, wave and current is resisted by the buoyant force offset horizontally from the anchorage and from bending induced at the top and bottom of each pile by the bending members.

INTRODUCTION

Long Buoyant Flexible Pile Frames are very long cylindrical steel piles are anchored at the sea floor and are rigidly connected to bending members near the water surface. Figure 1 shows a typical four-leg design. The bending members will restrain joint rotation and thus keep the tops of the piles very close to vertical alignment. The piles could be anchored by being driven into the sea floor; however, because they are most likely to be used in very deep water, the more practical anchorage would be with skirt piles. Bottom trusses connect the skirt piles to the Buoyant Piles and also connect Buoyant Piles to one another. The piles have watertight bulkheads with the piles open to the atmosphere above the bulkheads and open to the water below the bulkheads. The top bending members are rigidly connected to each Buoyant Pile. If the bending members connect two or more piles, they form a simple rigid frame.

Figure 2 shows a single-leg design. The top bending members of this design are rigidly connected to the Buoyant Pile with their other ends (outboard ends) connected to steel tendons which keep the bending member very close to horizontal alignment and keep the platform level.

Figure 3a shows a four-leg rigid frame design with depth and Buoyant-Pile diameters noted. Figure 4a shows a similarly noted single-leg design.

This paper is based on design and analysis in compliance with API RP 2A using assumed operating requirements and environmental forces typically associated with the Gulf of Mexico.

MAIN PRINCIPAL

Long Buoyant Flexible Pile Frames have two important components that cause them to be stable and to resist the environmental forces of wind, waves and current (WWC forces). The first component is the rigid-bending connection at the anchorage and the top of the piles. As the WWC overturning forces cause the tops of the buoyant piles to move laterally, as in Figures 3b and 4b, bending moment is induced at the anchorage and at the pile tops. The induced bending moments are righting moments.
The Central Area Transmission System (Cats) And Central Graben Development
Authors: Haynes M.D.
Published: October 2008

The central Area Transmission System (CATS) provides a common gas gathering and transportation facility that has the potential to open up the development of gas reserves in the Central Graben Area of the North Sea. Completed in 36 months, the $2.1 billion project will be capable of carrying 1.6bcf per day direct to the UK5 industrial heartland and includes the development of the North Everest and Lomond gas fields. This paper outlines the technical and complicated commercial background to the project and the facilities it comprises.

INTRODUCTION & BACKGROUND

The Central Area Transmission system (CATS) is part of the Central Graben Development project being developed by two separate groups of companies led by Amoco (U.K.) Exploration Company and on behalf of its Co-Venturers. The project involves the development of two offshore gas fields, Everest and Lomond, approximately 120 miles east of Aberdeen and the construction of a 254 mile, 36 inch diameter pipeline to Teesside in the north east of England, where the gas will be metered by a new offshore terminal. The first 300 million cubic feet of gas per day produced through the system will fuel a new combined cycle electricity plant recently.

Completed at Teesside, though the pipeline itself will have the capacity to transport approximately 1.6 bcf per day thus opening up the possibility of further gas field development in the central area of the north sea and third party use.

The genesis of the CATS project lies in the discovery of the Lomond field in 1973, followed by the Everest discovery some 10 years later. Together these two fields contain an estimated 1.5tcf of gas and 50 MM blls of condensate, lying approximately 14 miles apart, and were judged capable of sustaining a plateau delivery rate of around 300 MMSCFD of gas per day for about 10 years before going into decline. As single fields they were too small to be commercially attractive being some 120 miles offshore but sold together were viable.

MARKETING NEGOTIATIONS

In 1985 marketing activity was initiated. First a study was prepared in which evacuation routes were investigated. The study looked at land falls along the eastern coast line of Great Britain, the market potentials for the liquids stream and the potential for gas markets outside of the traditional customer, British Gas. Government attitudes and policies were changing at this time and gas sales to other industries were becoming possible.

Two obvious directions emerged from the study that identified Teesside (North East England) and St. Fergus (Scotland) as the best land falls for the pipelines. With its heavy industry base and good harbour facilities, Teesside held more future potential for gas and liquid sales. British Gas was clearly a potential buyer for the gas but it was ICI/ENRON who emerged as the eventual buyer.
Life-Cycle Cost Reduction Through Designing For Maintenance
Authors: Songhurst B.W. , Kingsley Mark
Published: October 2008

Significant offshore development cost savings were made during the 1980's by adopting the minimum facilities approach. However, this approach was based essentially on CAPEX reduction. To make further savings, OPEX reductions must now be addressed and development costs prepared on a field life cycle basis. Such savings can be made by reducing the frequency and amount of intervention required and this paper presents technologies and approaches which could be adopted at the conceptual engineering phase.

Introduction

Trying to gauge, in absolute terms, the health of the offshore industry in the British Sector of the North Sea is currently not easy, with seemingly conflicting messages being reported by the media. On the one hand, some commentators have expressed the view that the North Sea is inherently a high-cost, modest-reward production area. On the other hand, bullish predictions are being made about record production levels and number of fields in production by the end of this century.

What is clear is that a large number of fields left to be developed in the North Sea could be considered to be marginal developments. What is also clear is that while activity is high at the moment, the outlook is uncertain. Within the international oil companies, the North Sea is more than ever having to compete against other parts of the world for funds to finance projects. Good examples are Indonesia and Malaysia, with established, sophisticated and energy intensive markets such as Japan and Korea nearby and other emerging nations, such as Thailand (8-10% growth in GNP in each of the last five years) on the doorstep. It is hardly surprising then that Exxon is currently reviewing development options for its giant Natuna gas field. Other markets competing for funds are also the Middle East, South America and the former USSR.

To maintain activity and investment in the North Sea, we must attempt to maximize the potential value of the remaining hydrocarbons. One tangible means of doing this is by driving development and operating costs further down and thus making these marginal fields economically viable on a worldwide basis.

Minimum Facilities Platforms Traditionally the specific quantitative goals for a project, as defined by the Operator at the design phase, are focused on capital cost (CAPEX) and schedule. The success, or otherwise, of a project is measured against these specific criteria. Since the oil-price crash of 1986, considerable progress has been made in reducing both project CAPEX and realisation schedules.

In particular, development costs have been reduced by adopting a systematic and rigorous approach to platform design which has become known as "bottom-up" engineering from a "Zero-Based" design. The platforms designed using this approach have become known generically as "Minimum Facilities" and range from small Southern North Sea not-normally-manned platforms, to large Central North Sea oil and gas platforms such as Shell/Enterprise Nelson and Chevron Alba.
The Effect Of Corners On Diffraction/Radiation Forces And Wave Drift Damping
Authors: Taylor Rodney Eatock , Teng Bin
Published: October 2008

A high order panel method has been developed for the calculation of wave diffraction and radiation by a moving body with a small steady forward speed. This has been used to compute results for a series of truncated cylinders with the same radius and draft but different comer radii. The results show that the most important hydrodynamic forces and amplitudes of body motion do not change significantly when the radius of the comer approaches zero. This suggests that even though in theory the potential flow solution is singular when the radius of the comer approaches zero, it is still possible to describe the body surface by a sharp comer in practical calculations, and to use the same method as for smooth bodies.

INTRODUCTION

Many moored and compliant offshore systems in deep water have low natural frequencies in their horizontal modes, which can be excited in random waves. As the low frequency response is a resonant phenomenon, it may only be predicted if adequate knowledge is available concerning low frequency damping. During low frequency excitation, wave drift forces are varying with the change of speed of the floating body, and this variation of the mean drift force can be considered as causing a form of damping. At any instant the action between the body and the fluid can be approximated as the problem of the body moving with a steady forward speed.

Wichers1 defined the rate of change of the mean wave drift force with forward speed as the wave drift damping. Research has shown that the drift damping plays a role similar to that of viscous damping in the low frequency behaviour of a floating body.

The prediction of wave drift damping depends on accurate calculation of velocity potentials diffracted and radiated by advancing bodies. In this respect, significant progress has recently been made2–6. For the calculation of the potential flow problem around floating bodies with steady forward speeds, the integral equation method is widely used. Using a Green function which satisfies the free surface and the far field conditions, the integration domain can be limited to the body surface and a small area on the free surface.

Recently a higher order method has been applied to this Problem7. Higher order methods can provide accurate descriptions of body surfaces, and it is believed that they can also give accurate and continuous results along a discretised body surface. The difficulty in applying higher order panel methods lies in having to specify the solid angle of the body surface, and calculation of some singular integrals which exist only in a Cauchy principal value (CPV) sense. For the zero speed problem this can be avoided by indirect methods; for example, Noblesse8 and Chau and Eatock Taylor9 used another companion boundary integral equation inside the body, combined with the original integral equation, to cancel the solid angle and CPV integrals. For the radiation problem of a moving floating body with steady forward speed there are however other CPV integrals in the boundary integral.
Improved Soil Characterization For Pipe Piles In Sand In Api Rp-2A
Authors: Hossain M.K. , Briaud J.L.
Published: October 2008

In the offshore, most foundations are steel pipe piles and most of them are designed using the API RP 2A guidelines. For axial capacity of piles in sand the current guidelines in many cases show definite discrepancies when compared against actual load capacities of piles. An updated data base analysis shows that there are three major weaknesses in the current guidelines with respect to soil characterization:the consideration of the lateral earth pressure coefficient, K, as a constant (1. O or 0.8);the consideration of the unit point bearing resistance, q, as a linear function of depth; andthe absence of an unambiguous soil parameter determination process based on reliable in situ test results.

Due to the erroneous assumption of a constant K, the API RP 2A guidelines show a "length effect;" it tends to under predict the capacity of shorter piles and over predict the one of longer piles. Consideration of q as a linear function of depth coupled with a step function bearing capacity factor, Nq, also contribute to over prediction for long piles, and wide variation in the prediction between users for short piles. The absence of an unambiguous in situ test method simply add to the overall discrepancies in the predictions.

In this paper, specific modifications to the current API RP 2A guidelines are proposed on the basis of a data base analysis to account for the discrepancies arising from (a), (b), and (c) above. These modifications will reduce the discrepancies in the current API RP 2A method and increase the accuracy of the prediction of axial capacity of pipe piles in sand. Furthermore this will make the method fundamentally more consistent with soil behavior in deep foundations.

INTRODUCTION

The American Petroleum Institute (API)1 published its first set of recommended practice for planning, designing, and constructing fixed offshore platform in 1969. Since then it gained worldwide popularity and usefulness in the geotechnical community. However, along with the success it also drew criticisms, which led to its improvements2 over the years.

This paper includes the results of a data base analysis of pipe piles in sand. The current data base is the updated version of a previous load test data base3 of piles in sand.

THE DATA BASE

Most offshore foundation piles are piles. In this paper the updated data the load tests of pipe piles in sand, It driven steel pipe base only includes consists of 60 load tests at 18 onshore sites. Most of the tests are from the United States, with a few from Canada, Holland, Taiwan, Israel, Yugoslavia and Japan. The references to the sites including other relevant information are shown in Table 1.

The load tests of at least 11 of the 18 sites had already been considered in the revision and/or in the formulation of the API RP 2A previously.
Bearing Capacity Of Driven Model Piles In Dense Sands From Calibration Chamber Tests
Authors: Foray P.Y. , Colliat J.Y. , Nauroy J.F.
Published: October 2008

Model piles were driven and tested in samples of dense siliceous sands in a large calibration chamber at 3S/lMG, Univ. of Grenoble (France). Tension and compression tests were performed with both open-ended and closed ended pipe piles. The research programme aimed at providing geotechnical engineers with design parameters for piles driven into dense sands, focusing on points of interest for offshore piles, in particular:dense to very dense sands,tension versus compression skin friction capacity,high confining pressures (up to 800kPa) for simulating large penetration depths.comparison with cone penetration tests.

New design parameters are proposed for computing bearing capacity of piles driven in dense to very dense siliceous sands. They are compared with those given in the current API RP2A recommendations.

INTRODUCTION

Bearing capacity of offshore piles driven in dense siliceous sands has been, and continues to be, a controversial topic since API RP2A recommendations were changed in 1984 (1). The two main points of concern, relating to K values for compression and tension pile capacity and limiting values for skin friction and tip resistances, have a direct influence on offshore foundation costs as reflected by steel cost, driving equipment mobilization cost, installation time and cost for possible remedial measures. These changes are still not fully accepted and applied for the North Sea by certifying authorities and some geotechnical consultants preferring to adhere to the more conservative rules of API 82.

It is generally agreed that the uncertainty on computed axial capacity of piles driven in sands is large when using current API recommendations, and a statistical pooling of international experts concluded that the API criterion may be conservative by 20 to 40%. In dense to very dense sands (2), This is of particular concern for the North Sea where dense sands are encountered widely and where potential savings are important due to the large number of structures involved.

On the other hand, some studies (3,4) have indicated a tendency of the API method to under predict capacity of short piles and over predict that of long piles, due to the so-called "friction fatigue effect". Interesting contributions were made recently by Kraft (5,6) and by Randolph and Dolwin (7) where new design criteria were proposed for computing axial pile capacity in sands, considering that no data provided conclusive evidence of the existence of limiting values and that an optimistic K value of 0,8 leads to the over predicting of the capacity of short piles when using the API criterion (5,6). It is also suggested that the current API design method may be conservative mainly due to underestimation of the end bearing capacity of piles (7).

In an effort to improve our knowledge of the behaviour of piles driven in sands, an extensive experimental programme was conducted at 3S/lMG and supported by ELF Aquitaine Production and IFP. Model pile tests were performed in a large calibration chamber
Case Study Of Offshore Pile System Reliability
Authors: Tang W.H. , Gilbert R.B.
Published: October 2008

This paper presents the results of research effort to evaluate the reliability of offshore pile foundation systems. It is an extension of previous work by the authors [14] dealing with the reliability of individual piles under axial and lateral loading. The reliability of the pile system is evaluated for three ease study platform designs, and the level of reserve between initial failure of an individual pile within the system and system collapse is studied. The results of this research are valuable in providing insight into the reliability achieved with current design procedures and the factors which affect the performance of the foundation system. The results should facilitate the development of reliability based design procedures which provide for a consistent level of safety between different site conditions, loading conditions and pile configurations.

INTRODUCTION

Satisfactory performance of pile foundations for offshore oil platforms is an important consideration in design, and a better understanding of the reliability of platform foundations is important as design practices move towards reliability based systems. Evaluation of pile system performance is influenced by various sources of uncertainty including uncertainties in system loads, pile properties and soil properties. In addition,. uncertainty is associated with the inability to predict performance using simplified models of actual behavior. These uncertainties have traditionally been accounted for through a variety of conservative design practices extreme loading conditions are use~ soil properties are conservatively selected; deterministic safety factors are applied to the design, and design is often based on failure of the most heavily loaded pile in the foundation, not failure of the entire pile system. AH is currently in the process of formulating a reliability based design procedure for fixed platforms. The primary advantage of this approach will be to achieve a consistent level of performance reliability in platform design between different site conditions, loading conditions and piIe configurations.

In formulating a reliability based design procedure, the following questions arise:What level of reliability is achieved for an individual pile and for the pile system using traditional design methods?How do the various sources of uncertainty affect the reliability of the design?How much redundancy or reserve between initial failure and system collapse is built into the design?

Since 1986, a series of research projects has been sponsored by API to address these questions. Findings from the first two phases, which deal with the reliability of individual piles under axial and lateral loading, are summarized in [14]. The third phase concentrates on the reliability of the pile system and the relationship between the performance of individual piles within the system and the performance of the system. Details of this research are reported in [15], and the results are summarized herein.
Stress Corrosion Cracking Of Duplex Ss, (Jns S81803 On The Gyda Hp Separator
Authors: Øystetun Ingar , Johansson K.A. , Andersen O.B.
Published: October 2008

The duplex SS HP separator on the BPN operated Gyda platform suffered external SCC after 1 1/2 years in operation. The cracking occurred in two circumferential welds. Conditions creating SCC were seawater sustained in wet insulation, high residual stresses from welding and surface temperatures in the range from 40-100°C.

INTRODUCTION

The Gyda Platform, located in the Norwegian sector of the North Sea, is a single steel jacket PDQ platform (production, drilling and quarter) and is operated on behalf of the licensees by BP Norway Limited U.A.. Oil Production commenced in June 1990, therefore the HP separator had only been in operation for 18 months prior to the occurrence of the failure.

Fig. 1 shows an overall schematic of the production process on Gyda. The produced fluid from the wells flow to the production or test manifolds prior to entering the single production train or the test separator. The produced fluid then pass through two stages of three-phase separation where oil, gas and water are separated. The first stage is the HP separator, the second is the LP separator, respectively operating at 26 and 15 barg pressure. The oil stream is cooled between the two stages.

The HP separator design parameters are listed in the table no. 1.

The process plant is designed to handle a maximum of 70,000 STB/D of crude oil.

CRACK OBSERVATIONS

On 01 January 1992 a small leak of water was detected below the HP separator.

On 02 January an investigation team started the failure examination cm Gyda. With the removal of the insulation it was identified that cracks were clearly visible in the lower part of the vessels at the two central circumferential girth welds and at the oil outlet nozzle. After extensive NDE the following main cracks were identified (see fig. 2); 5 cracks on weld no. 1007, 25 cracks on weld no. 1008 and 12 cracks on the oil outlet nozzle (N3A). The maximum crack length was 230 mm, but the majority of the cracks did not penetrate through the vessel shell thickness. All the cracks were observed as being below the produced water/oil interface evel.

Fig. 3 illustrates the condition of the lower part of the vessel after removal of most of the insulation. One of the major and penetrating cracks is visible at the centre of the photograph. In addition there were brown corrosion products and salt deposits with evidence of pitting corrosion. The insulation was found to be soaked with water along two thirds of the vessel bottom, including all the areas where crocks were detected.

During the course of the inspection of all three separators, different NDE techniques were used with varying degree of success. Dye penetrant inspection (DPI) is a recognised method of NDE of duplex stainless steel. However, the Gyda experience showed that a rather long soaking time was required to detect the cracks. Internal cracks were very difficult to detect.
Snorre Project Execution: Lessons Learned
Authors: Solheim B.J. , Plummer F.B. , Gjerso Pål
Published: October 2008

The Snorre Field is the first truly deep-water development in the North Sea. It consists of the largest tension leg platform yet installed and a large, 20 well-slot, remote subsea production system. The platform went on production in August 1992 more than one month ahead of schedule and under the original budget.

The execution of projects with a high content of new technology can provide special challenges. The five Snorre papers are meant to provide feedback to the industry on how these challenges were addressed. They essentially pick up where the papers presented at the 1991 OTC left off (Ref. 1–6). This paper looks at the project execution, as a whole, while the others focus on specific topics such as installation, operations preparation, start-up, some innovative quality assurance approaches, and subsea experience.

INTRODUCTION

Over the past 15 years, a body of project management technology has developed in Norway which is suitable for managing large complex offshore platform developments. The Snorre project built on this foundation and added new techniques in the area of managing the development of new technology (required for deep-water) and in the area of technical risk management. While this is not the only way to execute large offshore projects, it has proven effective. It is expected that some of the principles will be valid elsewhere, as well.

This paper covers the overall strategies used by the Snorre management team. It then lists certain factors which have contributed to success, and areas for improvement, for each of the project phases. It is written in a point-outline format to make the key issues more readily visible and, hopefully, serve as a handy reference.

It concentrates on the lessons learned for the TLP itself. The Snorre marine operations are covered in some detail in OTC paper 7218. However, for completeness, the main lessons relevant to the TLP are included here as well. Likewise, the Snorre TLP operating experience is detailed in OTC paper 7220 with only the relevant experience highlighted here for completeness.

The subsea production system land test and installation experience is covered in a separate paper (OTC 7221) and will not be addressed here.

CONCEPT

The Snorre Field is located in blocks 34/4 and 34/7 in the North Sea, about 200 km west of Florø on the Norwegian west coast. Saga Petroleum is the operator and the other owners are Statoil, Esso, Deminex, Idemitsu, Norsk Hydro, Elf Petroleum Norge A/S, Amerada Hess, Enterprise Oil and DNO. Phase 1 of the Snorre Field development consists of a Tension Leg Platform (TLP) in steel and a Subsea Production System (SPS) (see Fig. 1). The water depth varies from 310 to 335 metres. Both installations are the largest of their kind in the world today. About 40 wells will be drilled from the TLP and 10 wells from the SPS with the possibility of another 10 wells if required. Oil and gas from both installations are part-processed on the TLP and shipped via pipelines to the Statfjord A platform, 28 km away, for final processing.
The Instrumentation Of The Conductor Of A Subsea Well In The North Sea To Measure The Installed Conditions And Behaviour Under Load
Authors: King G.W. , Solomon I.J.
Published: October 2008

The conductor design for subsea wells has not been studied to the same extent as the design of tie subsequent casing strings. To overcome this, models have been developed which Incorporate riser and pile foundation analysis techniques, however the models rue dependent on a number of assumptions on the installed conditions, applied load, and resultant behaviour which have not all been fully validated. There have also been cases where the structural failure of the conductor has resulted in the loss of a well.

To enhance the understanding of conductor design, a project was initiated to install sufficient instrumentation on the conductor of a subsea well, together with a data acquisition system, to enable the recording of the significant conductor parameters for comparison with model predictions. This paper describes: the objectives of the measurement program; the design and testing of the instrumentation systems; the offshore installation and operation; the results obtained ;and how they have been interpreted.

INTRODUCTION

The critical importance of the conductor to the structural integrity of a subsea well has long been recognizedl. Previous work has emphasized the need to transfer the loads applied to the wellhead to the conductor, and out through the cement into the soil. The loads are the result of the environmental forces of wind, waves and currents acting on the rig and riser, together with the static loads imposed by the subsea equipment. The potential for catastrophic conductor failure has also been confirmed2, and failure can occur from an excessive single load or from the cumulative â??fatigueâ?? damage of a large number of smaller cyclic loads.

The need to include conductor design in the design of a well has resulted in the development of analysis models which combine riser analysis and soil-pile interaction analyses to simulate the loading on a conductor3. Such models are invaluable for sensitivity analyses of a conductor to evaluate the effect of a range of parameters when precise values are not available. The parameters which typically need to be considered include: soil stiffness; cement height; hole diameter and environmental loads (figure 1).

A significant weakness of the analytical models is the absence of any field data against which hey can be validated. For inner string casing design the applied loads and installed conditions am reasonably well understood, conductor design has relied on assumptions of effective cement height and load transfer mechanics. Therefore it was decided to instrument a conductor for a North Sea well to measure the installed conditions and behaviour under load. The well would be a typical North Sea well using a standard well head system and casing scheme.

OBJECTIVES OF THE CONDUCTOR INSTRUMENTATION PROJECT

The primary objectives of the Instrumented Conductor Project (ICP) were:to record sufficient data on the installed conditions and response of the conductor to calibrate the analytical model analyses;
Technology For Full-Range Water-Cut Measurements
Authors: Scott B.N. , Cregger B.B. , Shortes S.R.
Published: October 2008

The ability to measure both water and oil continuous phases of a production stream from 0% to 100% water cut has been pursued by a multitude of companies for many years with marginal success in transferring the technology to practical use.

A field worthy technology developed for accurately determining the full range of water-in-oil (0-100% water cut) for production and well testing will be covered. Information about the fluid phase, oil or water continuous, is determined and given in real time. The novel technique used is called oscillator load pull, which detects the permittivity of the fluids. Salinity, temperature, entrained gas, and emulsion type effects will be discussed showing their effects on phase inversion and measurement parameters. Data from installed instruments on location in Alaska and the lower 48 states will be shown. Comparisons to shake-outs and well test logs will be compared. Descriptions of how the real time information of the phase of the fluids has been used to observe and affect well management will be presented.

INTRODUCTION

The accurate measurement of the water content in crude oil has been an ongoing problem in both the low water cut (0-4% water in crude oil) and the full cut range (0-100% water). These problems existed due to the limited sensitivities of earlier measurement methods and the conductivity of salt water which both limits the sensitivities available and makes the determination of the phase of the fluids a necessity.

A typical use for a full range water cut instrument is in well testing. The use of a full range instrument allows the use of only a two phase separator which reduces the size and complexity of the well test equipment while improving the reliability of the measurement. Since the entire fluid stream is measured at once and a totalizer tied to flow meters can give the net oil, the separate tracking of the water and oil legs is eliminated. The separate oil and water tank level controls are eliminated along with the associated errors with oil/water carry over to the water/ oil legs.

THE FLUID PHASES OF OIL AND WATER

An emulsion is a dispersion of one liquid in another where the continuous or external phase is defined as the matrix in which the droplets are suspended. The droplets which are surrounded by the continuous phase are called the discontinuous or internal phase.' The two types of emulsions will be abbreviated OIW for oil-in-water (water continuous) emulsions and W/O for the water-in-oil (oil continuous) case.

Generally, a well begins by producing W/O emulsions until water injection begins and the water cut increases over time to 70% or above. The point at which the well will produce water emulsions depends upon the emulsifier contents of the crude oil. Under laboratory conditions, West Texas crude oil will invert from W/O emulsions to O/W at approximately 88% water at 80 degrees F while injecting 5% salt water.