bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Generalized In-Line Vortex-Induced Vibration Assessment Method
Authors: Reid D.L. 
Published: October 2008

ABSTRACT
This paper identifies deficiencies and uncertainties in the present design procedures used for estimating inline (in the flow direction) vortex induced vibrations of circular cylinders in a near steady flow. A recently developed alternate design procedure which addresses some of these deficiencies, in particular non-uniform flow conditions, is discussed and compared with the existing methods.

INTRODUCTION
Vortex shedding from a bluff cylinder occurs in a wide range of flow conditions producing pressure fluctuations upon the cylinder. These fluctuations can excite structural elements with natural frequencies close to those of the pressure fluctuations and thus an assessment of this behavior is required in strength and fatigue evaluations during design.
This paper concentrates upon estimating the response of elements exposed to possible vortex induced excitation in the inline (with the flow) direction in a near steady current. During design possible vortex induced cross flow vibrations in both steady and unsteady (wave and current) flows must also be considered as well as wave induced inline motions.
Bronchi et al(1989)[ 1] indicates that inline vortex induced vibrations need only be considered when the peak wave induced velocity is less than 25% of the current velocity. Outside these conditions it is suggested that the unsteadiness of the flow inhibits the required vortex interaction from occurring and that the wave loading usually described by the Morison equation dominates the inline motions.

INLINE VORTEX INDUCED VIBRATIONS
For a detailed introduction to vortex shedding and its effects in near steady flows the reader is directed to King(I977)[2] and Griffin(I 981)[3].
The frequency of a vortex being shed from each side of a stationary cylinder in a Steady flow is described by the Strophes Number(St). This varies with Reynolds Number(Re) on a smooth stationary cylinder as presented in Figure I. The cross flow loading is dominated by this frequency while the inline loadings are around the frequency of shedding of individual vortices (? 2fv), In the zone 2xl05 &lt; Re &lt; 3xl06 the usually strong periodic vortex shedding is disrupted by the transition of the cylinder boundary layers from laminar to turbulent conditions. The location of this zone varies with surface roughness and turbulence levels. When a cylindrical structure vibrates in this zone, with surface roughness typical of marine structures, the usual narrow band vortex shedding is observed with a Strophes Number close to the lower bound of Figure I. For a particular structure, as St is nearly constant and (Vr)(St) = fv/fn then Vr describes the proximity of the system to a resonant condition.
Inline vortex induced excitation occurs, for a particular element, at lower flow speeds than cross-flow excitation, and thus although it produces much lower response amplitudes it may dominate fatigue assessments.
Burial of Vertically Loaded Offshore Pipelines in Weak Sediments
Authors: Dunlap W.A. , Bhojanala R.P. , Morris D.V. 
Published: October 2008

ABSTRACT
Cyclic vertical loads were applied to a 5' long, OS diameter model pipe, in order to simulate the effect on pipeline stability of various lift forces including waves, in addition to self weight. Experiments were carried out in a large sediment -filled tank, applying controlled vertical loads or displacements to the pipe section with a servo-hydraulic system. The cyclic and incremental movement and forces were electronically recorded, to provide data for the behavior of similar full scale structures, and for analysis of the problem.

INTRODUCTION
Marine pipelines can be subjected to a variety of environmental loading conditions from waves, currents and even nearby platform movements. At many locations where pipelines support the offshore petroleum industry, the pipelines rest on or are embedded in very soft clay-rich sediments. Repeated loading may cause the pipelines to bury in these sediments. In some instances this may be desirable, but if a buried pipeline is subsequently subjected to transverse loads or vertical pullout, large bending stresses and pipe distress may result.
In an earlier paper (Morris et aI., 1988), the effect of repeated transverse loading on pipeline behavior was addressed. The present paper discusses vertical pipeline loading and can be considered a companion to the earlier paper. The investigative approach was the same for both studies: experiments were conducted using a model pipe subjected to loading in a soft sediment. By the use of appropriate non-dimensional relationships, results from the model test can be scaled to predict prototype pipe behavior.

EOUIPMENT AND TEST PROCEDURE
All tests for this study were conducted in a sediment filled tank which was 6' × 6' in plan view and 4' deep. A false bottom was placed in the tank to limit the sediment depth to 30". The tank was filled with a calcium betonies mixture which had 53% clay (0.002mm), 42% silt and 5% very fine sand. The liquid limit was 101 and the plasticity index was 62, which classified the sediment as a CH (Unified Soil Classification System). Water content of the sediment was continually monitored during the test program and adjusted to maintain an untrained shear strength range of 20-30 lbs/sq ft.
Vertical loading and/or displacement of the pipe was controlled with a closed loop, servo controlled hydraulic actuator. The actuator was mounted on a frame positioned alongside the test tank; a lever arm which pivoted on the edge of the tank transmitted motion from the actuator to the pipe. A load transducer mounted between the pipe and lever arm measured forces on the pipe and a linear variable differential transducer (LVDT) mounted on the pipe measured the vertical pipe movement. To ensure that the pipe moved only in the vertical direction, guide rods were attached to the ends of the pipe; these rods ran through linear ball bushings which were mounted on a beam spanning the test tank (Fig. 1).
Development of an Advanced Subsea Wellhead System Incorporating All Metal-to-Metal Sealing
Authors: Danner B.L. , Henderson H.O. 
Published: October 2008

ABSTRACT
This paper describes the design, analysis, testing and the resources devoted to the development of an advanced sub sea wellhead system. This wellhead system significantly improves casing suspension/load capacities, annulus sealing and rig floor operations.

INTRODUCTION
Wells are now being drilled in water depths over 7,500 ft. with reservoir pressures approaching 15,000 psi, and temperatures approaching 180°C. A high-performance sub sea wellhead system providing simple rig operations, reliable sealing and improved load carrying capacity is an important element in safely and cost effectively drilling and developing deepwater fields.
In developing this system, major emphasis was placed on:passive load transfer.All metal SealingSimple weight set operation. These elements, combined with other specific system performance goals, provided the benefits necessary to warrant this project. The approach was to define a specification based on historical perspective and present day customer input, to design and analyze the elements using the most modern technique: available, to rigorously and thoroughly test the equipment under laboratory and field-simulated conditions, and to perform field trials. The wellhead resulting from this research is shown in Figure 1.

Specification
The detailed specification is a lengthy document covering all associated equipment from spud-in to tieback and sub sea completion interfaces. The basic requirements for the wellhead are:18-3/4 in. -15,000 psi rated working pressure.compliance with industry specifications: API 17D, NACE MR-01 75, and Certifiable for North Sea operations.Temperature range - 4°C thru + 120°C.Simple reliable installationWeight set operation.Passive casing suspension load carrying system.Single trip installation of hanger and seal assembly.Minimization of the number of trips and tools.Load carrying capacity -7.1 million lb.1 million lb. per hanger (13-3/8 in., 9-5/8 in., 7 in.).4.1 million lb. end-load due to 15 Ksi full bore test.Highly reliable all metal sealing.Maximized flow-by area and particle size.Compatibility with sub sea production systems as well a platform or TLP tieback systems.

DESIGN

Wellhead Housing
The external design of the housing is standard and can be fitted with a mandrel or a hub profile to interface with the BOP stack connector. The load transfer system from casing hanger to wellhead housing is completely passive as shown in Figure 2. Unlike previous systems, no mechanisms, shear pins or addition trips are required to provide over 7 million lb. of load carrying capacity. The high-strength load shoulder insert in the wellhead housing has bore clearance for a 17-1/2 in. bit. The pre-installed wert provides additional bearing area on the NACE-rated housing material while maintaining 360° of contact with the first casing anger. This hanger-to-housing interface allows the hanger to simply land upon a conventional angular shoulder while maintaining the ability to support a load-tested 8 million lbs.
Direct Determination of Sling Tensions in Heavy Rigging
Authors: Crull C.M. 
Published: October 2008

ABSTRACT
Industry standards governing the design of heavy offshore lifts are limited in scope with regard to analytical techniques, particularly when sling length variation is considered. This paper presents approximate and exact methods for determining sling tensions, regardless of lift configuration. A parametric study examining critical features in lift geometry is presented.

INTRODUCTION
Throughout its history the offshore industry has moved to heavier and heavier offshore lifts in order to obtain the economies provided by minimizing offshore hookup time. At present there is at least one heavy lift vessel capable of lifting 14,000 metric tons operating. The economic risks associated with these heavier lifts make it imperative that engineers understand the implications of their lift analyses.
Current industry design standards, such as those of API and DnV, are adequate for situations which they cover. For situations where sling length variations exceed standard tolerances, which is common, or unusual sling configurations are used, guidelines provided put the burden on the engineer for analyzing and defining acceptance criteria for rigging.
To analyze this type of problem, this paper presents both approximate and "exact" techniques for analyzing sling configurations, either regular or unusual, which include slings with length variations. While the techniques presented are applicable to any size lift, the author originally developed them for lifts of 1,000 tons or more.
Exact analyses of rigging considering length variations in slings are non-linear. The approximate solution presented herein can be incorporated in an electronic spreadsheet for rapid solution of such problems. It provides results adequate for preliminary design and, under many circumstances, final design.
A technique is presented whereby the engineer can make an exact analysis of such non-linear systems with linear finite element analysis programs. Both solution methods were developed for single hook lifts. The exact solution principles can be extended to multi-hook lifts.
To quantify some of the variables in a lift analysis, a parametric study was performed. Results of this study can be used by engineers as an aid in recognizing which factors are more important in a lift analysis and which are less important. Help in determining when an approximate analysis is appropriate and when an exact analysis is justified is also provided by the parametric study. Brief comments on load factors for sling design and on in-plane deck bracing are included.
The primary aim of the techniques presented is to provide analytical methods for determining sling tensions, not stresses in the lifted structure. Once accurate sling tensions are available, analysis of the lifted structure is straightforward.
An External Scheme for Strengthening Offshore Platforms
Authors: Game W.J. , English K.G. 
Published: October 2008

ABSTRACT
This paper will describe the method by which Esso Australia Ltd. has substantially upgraded four of its oldest producing Bass Strait Platforms. The method involves the installation of one or two pile struts on the West side of each platform and the implementation of associated On-Platform Strengthening.
This innovative strengthening scheme will be described in sufficient detail to allow its direct application to other jacket type structures which may require strengthening. The paper will also put emphasis on the engineering challenges that were associated with implementation of the strengthening of the platform jackets and placement and connection of the pile struts to the jacket and sea-bed.

INTRODUCTION/BACKGROUND
Esso, as operator of a joint venture with BHP Petroleum (Bass Strait) Pty. Ltd. (BHPP), currently has 18 oil and gas producing facilities in Bass Strait (Figure 1) situated off the South Eastern tip of the Australian mainland. The first five of these, Barracouta, Marlin, Halibut, Kingfish A and Kingfish B, known as the First Generation Platforms (FGPs), were designed and installed in the late sixties.

Important Producing Platforms
These FGPs continue to playa vital role in the Bass Strait oil and gas production system. Halibut is the most important platform to the Joint Venture as essentially all Bass Strait oil either flows through or is produced from this platform. In 1989 this amounted to an average of 3l0KBD and represented over 60% of Australia's crude oil production which equates to approximately 47% of Australia's crude consumption. Marlin, Barracouta and Snapper platforms produce all sales gas required for the State of Victoria.

Platform Evacuation Policy
As we came to a greater knowledge of Bass Strait sea states and behavior of calcareous soils, it was clear that safety margins on the FGP's in storm conditions were less than desirable. In the early seventies a staged evacuation of personnel was instituted when storm conditions were forecast.
Required Ultimate Platform Strength For comparison purposes the term "reserve strength ratio" (RSR) was used as a reference of platform global strengths. (MATHEMATICAL EQUATION AVAILABLE IN FULL PAPER) A minimum target RSR of 1.5 was adopted for the FGP platforms to be consistent with the intent of generally accepted design practices. Personnel storm evacuations would continue until this target was achieved.

Strengthening Options
In 1985 Esso/BHPP decided to structurally upgrade all FGPs to a minimum RSR of 1.5 and thereby enable continuous manning. The desired increase in calculated global strength could be achieved most cost effectively by marine growth control for Barracouta and pile struts (struts) for the other platforms - one each for Kingfish A, B and Halibut (Figure 2) and two for Marlin (Figure 3). Guy lines could also have achieved the desired strength increases but were deemed more expensive. A more detailed explanation of the strengthening approach is given in Reference 1 and summarized in Reference 2.
Jolliet TLWP Well Systems
Authors: Myers R.J. , Delgado J.H. 
Published: October 2008

Abstract
This paper cut lines the unique features of the Jolliet Project well Systems. same of these features are as a result of experience gained on the Hutton tension leg platform, while others came as a result of special condition relative to the Jolliet Project.
The paper describes the systems starting at the drilling template, moves up the production riser to the surface support facilities and finishes with the internal completion.

INTRODUCTION
The well systems on the Jolliet Project Tension leg well Platform (TLWP) comprise the components of the production riser system. Full size tension leg platforms may have tensioned production, export and drilling risers. In the case of the Jolliet Project, all wells were predrilled and work over?s will take place through a 9-5/8 inch casing. Cot1segUently, there is no need for a drilling riser as no new drilling, apart from sidetracks cut of a cased hole, is anticipated. The export risers are flexible pipeline risers to minimize weight am tie-ins on the TLWP.
The production riser system (Figure 1) consists of the sub sea wellhead which sits in the drilling template receptacle, lower riser connector, tapered joint, riser pipe, special top riser joint, wellhead, Christmas tree and tensioned. sitting inside the production riser is the internal tubing completion.

WELL SYSTEM Components
Long Wellhead Receptacles (Figure 2) one of the requirements of a TLP production riser system is to install the 30 inch wellhead vertically, as this in turn sets the verticality of the 18-3/4 inch high pressure housing. Anyl deviation from vertical in the high pressure housing has a detrimental effect on the fatigue life of the production riser.
The long wellhead receptacle (15 feet) has reduced diameters at the top and at the bottom that restricts the 30 inch casing angle to I' when it is being run am the 30 inch wellhead housing to 0.5' when installed. This system may be used with jetted or dynadrilled casing.
The receptacles form part of the well pods installed on the drilling template [1]. Because they do not serve as structural members, the receptacles were lightened with large, cut windows to reduce the in-place and lift weight of the well pods.

Guide Posts (Figure 3)
There are no permanent guideposts installed on the drilling template. The posts are removable and are installed each time a riser is run or drilling takes place. '1bey latch by means of their own weight into a receptacle and are released by a hydraulic tool that can be run on a FDV or on drill pipe from the surface.
An Appraisal of API RP2A Recommendations for Determining Skin Friction of Piles in Sand
Authors: Toolan F.E. , Lings M.L. , Mirza U.A. 
Published: October 2008

ABSTRACT
API RP2A in its 14th edition (1984) recommends the use of an earth pressure coefficient of 0.8 for computing the tensile skin friction of an open ended pile driven into silica sands. In view of the impact of this recommendation on the design of North Sea piles driven into sands, a study was made of an expanded data base on the pull-out capacity of piles driven into sands. The expanded data base includes test data on relatively long North Sea conductors and in all 24 tension tests considered of reasonablyhigh quality were analysed. The new data base together with observations of pile behavior in sand has enabled the authors to develop two procedures for designing piles in sand. These two procedures differ from API in allowing skin friction to reduce at a given level as a pile is driven deeper. Comparisons of predicted and measured capacities of the test piles were made and compared to API (1984) predictions. It is concluded that the API Method is not reliable for loose or very dense sand sites. The two new methods provide much better predictions in these soil conditions.

INTRODUCTION
The Document API RP2A (Ref. 13) is updated regularly in the light of experience and research. From the foundations point of view, a major change was introduced in the 1984 issue (14th Edition) with regard to the assessment of skin friction of pilesdriven into sands. The 1984 and subsequent issues of API recommend using a coefficient of earth pressure, K, value of 0.8 for computing both compressive and tensile friction capacities of an open ended pile driven into silica sands. This recommendation may be compared to the pre 1984 practice where K values are taken as 0.5 and 0.7 for tensile and compressive loading, respectively of an open ended pile. One ingredient that has lead to the current API recommendations was the conclusions from the API supported study of Dennis and Olsen (Ref. 14) which collected and examined the data for 66 closed andopen ended driven piles, tested in compression and in tension.
The substantial increase of 60% in the K value for tensile loading has a major implication on the design of North Sea piles in sand. As a result, the Department of Energy and Fugro-McClelland supported a study in which the data base for pull-out tests on piles driven into sands was re-evaluated. This study which was reported by Lings (Ref. 15) consisted of re-interpreting the load test data and thesoil conditions for some 20 tests which were considered more reliable than others. The data base included proprietary data from a pull-out test on a 38m long conductor driven into dense to very dense North Sea sands. Lings I s conclusion was that the API (1984) method appears in general to give satisfactoryresults for piles up to 60 diameters penetration while at greater depths, the method seriously over predicts pile capacity. In a more recent work reported by Toolan and Ims (Ref. 16) the current API method for sand was also examined and shown
Developments in Fatigue Design Guidelines for Anchor Chains as Mooring Lines
Authors: Sincock P. , Lalani M. 
Published: October 2008

Abstract
This paper discusses the specification and design of moorings using anchor chain, with particular emphasis on long term mooring. A brief review of historical field data of offshore platform chain mooring lines is first presented. Current design methods for determining fatigue life and extreme loads for chain moorings are then discussed and compared.
With the numbers of floating production systems and other installations which use long term moorings growing rapidly, it is suggested that fatigue willbecome an increasingly important design parameter for all moorings. The majority of current Design Guidelines give only limited guidance on the design of chain moorings for long term position mooring. All test data on anchor chain fatigue life presently in the public domain is presented in both tabular and graphical formats. A detailed appraisal of this data is made.
It is concluded that there are a number of areas which warrant further study in the development of design guidelines for chain moorings, particularly with respect to fatigue life. This is currently the subject of an extensive joint industry research and development project in Europe, and is discussed in detail in this paper.

Introduction
Anchor chains are a widely used means of catenary mooring for both Mobile Drilling Units (MDUS) and, more recently, Floating Production Systems (FPSS). In addition other offshore structures, such as tanker single point moorings and spar loading buoys are frequently moored by means of chains. Ships almost universally employ chain anchor lines.
The design of anchor chain links, known as "common links", is over 100 years old and their dimensions follow a standard which is international (l), (2). Common links are made from a length of round steel bar, which is bent into a loop with straight sides, figure 1. The ends of the bar are flash butt welded, the join being positioned on one of the straight sides of the loop. A short length of rounded bar with shaped ends, known as a stud, is fitted between the straight sides of the loop. The primary purpose of the stud is not, as might be imagined, to increase the strength of the link, but to prevent the chain becoming tangled when slack. The stud is fixed in place by squeezing the sides of the loop inwards. For further security the end of the stud opposite to the flash weld may be welded to the loop.
Chain for ships is supplied in three grades, referred to as Grades 1, 2 and 3. For offshore use, chain of greater strength than these ship grades is normally specified. The chain grades most commonly used for offshore applications are K3 and ORQ (Offshore Rig Quality), which are essentially equivalent grades. Recently, however, two chain grades of higher strength than K3 (ORQ) have begun to gain in popularity for offshore use. These are 0RQ+20% and K4, which are approximately 20% and 30% stronger, respectively, than K3. A third grade, K5, which is stronger again than K4, is also likely to find increasing favour in the future.