bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design Provisions For Offshore Grouted Construction
Authors: Seie Arne , Skjolde Monica 
Published: October 2008

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

Abstract
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

ABSTRACT
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

ABSTRACT
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.