bluuebunny/crossref_metadata_2025_split huggingface dataset:
Method for Laying and Connecting Intrafield Flowline Bundles in Deep Water
Authors: Coleman James T. , Saliger Kenneth C. , Yancey I.R. 
Published: October 2008

Abstract
This paper presents a method for simultaneously latching both ends of a floating flow line bundle remotely to two subsea structures and laying on the seafloor without the use of divers. The entire multiplied bundle is fabricated onshore, fitted with end termination assemblies and pressure tested prior to launching. The bundle is then launched and towed near the surface to the installation site. Drawdown cables pivoted on the sea floor are attached to each bundle end and to heave compensated surface winches. Both ends are then hauled down and mechanically latched to the sea floor structures. The entire bundle takes an inverted catenaries configuration. With the two surface support vessels controlling the pipe bundle end tensions and a control vessel acoustically monitoring the bundle configuration, the pipe stresses are determined and controlled within allowable limits. After mechanical attachment to the sea floor structures, the buoys are selectively released allowing the flow line bundle to lay on the sea floor.
A specially designed connector tool, run from each surface support vessel, completes the installation by remotely removing the test cap from the bundle end pipe mandrel and hydraulically connecting the bundle to the subsea structures.
This method was successfully demonstrated during 1980 in the Gulf of Mexico on a commercial installation.

Introduction
Offshore exploration drilling is continually moving into deeper water. This presents an ever increasing challenge to deepwater subsea production systems. Since the mid-60's Mobil has been active in the development of deepwater production systems. In the early development stages, it was realized that pipe laying tension forces to control bending and collapse stresses using conventional pipe laying techniques were water depth related and, therefore, posed some finite practical water depth limitation. In addition, remote, driverless second end connections would be complicated and difficult in deepwater.
Various feasibility and trade-off studies were conducted and resulted in the concept of "The Simultaneous Drawdown Method". This paper presents "The Simultaneous Drawdown Method" for installing flow line bundles up to 12,000 feet in length for water depths in excess of 1,000 feet.
A flow line bundle is defined as two or more pipes in a common carrier with single piece, multi-bore end terminations. Both ends of the buoyant bundle are hauled down and latched to seafloor structures with the bundle taking the shape of an inverted centenary. This method has the following advantages: (See Figure I)Eliminates the complications of a second end connection by making two first end connections simultaneously.Allows installation forces and pipeline stresses to become insensitive to water depth.Has the unique ability to install a bundle whose length is less than water depth.Provides for the entire flow line bundle to be fabricated and tested onshore prior to mobilization offshore.
Stand-By Rescue Ships - Their Roles and the Factors Involved in Performing Them
Authors: Sykes John , Hibbett Hollobone 
Published: October 2008

ABSTRACT
This paper is based on a study, led by the author, which was completed in 1981 for the UK Department of Energy and which led to the publication of Draft Guidance Notes for the operation of Rescue Ships in the UK Sector of the North Sea. The paper examines the requirements for independent rescue facilities for offshore installations and concludes that such facilities are needed. It goes on to discuss the requirements of such vessels in material and personnel terms. In particular it considers the relevant topics of vessel design, pick-up boat design, propulsion and launching systems, medical capabilities, communications and personnel selection and training Its conclusions highlight the main features of the Draft Guidance Notes for Rescue Ship Operations.

INTRODUCTION
Stand-by Vessels have been required by law to be stationed in the vicinity of offshore installations in the North Sea for several years. They were first introduced in the UK Sector after the loss of the drilling rig Sea Gem in December 1965 when 13 people died. British law demands that a vessel shall be present within 5 nautical miles of every offshore installation when it is manned, ready to give assistance in the event of an emergency on or near-the installation. The vessel is required to be capable of accommodating and providing first aid to all persons who may be on the installation at any time and to have primary and secondary means of communication with the installation. More detailed requirements for the vessels are issued by the UK Department of Trade. The Department?s Surveyors are required to have issued a Certificate of Survey for each vessel before United Kingdom Offshore Operators Association members will employ it as a Stand-by Vessel in the UK Sector. Similar arrangements exist in other North Sea Sectors. Thus it is that all operators of offshore rigs and platforms in the North Sea have employed certified vessels to stand by within 5 nautical miles of their installations at all times.
Perhaps because these vessels have sometimes been chartered more to fulfill the requirements of the law than because of any conviction that they are needed for a practical purpose, they have tended to be of a standard sufficient to obtain a Certificate of Survey but no more. It can, and has been, argued that this standard is insufficient for the role they are there to fulfill, but before this can be examined, it must be clearly established that a genuine role exists. If it does, the capabilities of vessels needed to perform it can then be assessed. The study upon which this paper is based set out to do this.

CONDUCT OF STUDY
The study took the form of some fifty so discussions with a very wide variety of companies and organizations connected with Stand-by Vessels and visits to Stand-by Vessels operating offshore. The people performing the study, and subsequently drafting the guidelines had considerable marine and offshore industry management experience but had no vested interest in the outcome of the study.
The Tarsiut Island Monitoring Program
Authors: Weaver J.S. , Berzins William 
Published: October 2008

ABSTRACT
This paper presents a description of the monitoring programs used during construction of Tarsiut Island and during the drilling of the Tarsiut N-44 exploration well. The objectives of this program were threefold:To ensure that the island was constructed according to acceptable design standards.To ensure that the island performed satisfactorily under the imposed environmental loads throughout the drilling of the Tarsiut N-44 exploration well.To collect data that could be used to streamline the design of future islands.
A description of the monitoring strategy and instrumentation is presented. Typical results are reviewed and recommendations for future programs are given.

INTRODUCTION
Tarsiut Island was the first artificial caisson-retained exploration drilling island constructed in the Beaufort Sea. The island was built during 1980 and 1981 by Canadian Marine Drilling Ltd. on behalf of the operator, Gulf Canada Resources Inc. A description of the design and construction of the island is presented by Stenning and Fitzpatrick (1983).
The layout and dimensions of the island are summarized in Figure 1. This drawing represents the island as it was designed for drilling the first exploration well during the 1981-82 winter.
The island represents a benchmark in the design of Arctic drilling platforms. It was not only the first caisson retained island in the Arctic, but was also the first island to be built outside the 1and fast ice zone. Furthermore, Tarsiut was regarded as the prototype of possible future production platforms in the Beaufort Sea. With this in mind, Gulf et al committed to an extensive monitoring program, the objectives of which were threefold:To ensure that the island was constructed according to acceptable design standards.To ensure that the island performed satisfactorily under the imposed environmental loadings throughout its design life.To collect data that could be used to streamline the design of future is1ands.
A quality assurance program was implemented in order to achieve the first objective. The second objective was satisfied by monitoring the response of the island under ice and gravity loads. This " operational monitoring" program was implemented during the drilling activities on the island and was integrated into the alert and evacuation procedures.
A comprehensive research program was put into effect to satisfy the third objective. This work was primarily orientated to collecting data on winter ice forces and island response to these forces. Geotechnical data on caisson "setdown" pressures, island settlements, and ground temperatures were al so collected as part of the research program.
The remainder of this paper describes the monitoring strategy and instrumentation for each of the monitoring programs. Examples of typical results are presented and recommendations for future monitoring programs are also given.
Anchor Holding Tests in the Norwegian Trench
Authors: Void R.C. , Eie John 
Published: October 2008

ABSTRACT
Two series of pulling tests, made on four types of commercial 3-ton anchors at 300 m water depth in the open sea west of Bergen, are reported. The first series included full instrumentation of the anchors while in the second series only anchorline tensions were measured. The seabed consisted of soft silty clay. The resulting holding capacities were extrapolated to larger size anchors.

INTRODUCTION
The depression known as the Norwegian Trench runs for some 400 n. miles parallel to the coast of south Norway. Its width varies between 30 and 60 n. miles and its depth between 300 and 800 m. Being much deeper than the North Sea in general it presents difficulty for pipelaying between the petroleum fields on the Norwegian Shelf and mainland Norway. Since the surficial seabed sediments are very soft there has been concern as to the anchor holding capacity for operation of lay barges.
The Statoil/Mobil group in 1977 undertook to investigate the performance and holding capacity of various anchor types by means of large-scale field testing in the Trench. The test program was part of the Statfjord Transportation System Project and based on a contract between Statoil and Oil Industry Services A/S. A cooperation agreement was made between OIS, Lindboe and NOTEBY. The Central Institute of Industrial Research and A/S Teleplan were engaged for specialized instrumentation.

PHASES OF PROGRAM
The work was performed in partly overlapping phases as follows:Planning of test proceduresPreparation and calibration of instrumentationProviding vessels, anchors and equipmentSampling and testing of seabed soilsFunctional pre-testing in sheltered waters (fjords)Main testing at seaData processing, reporting and evaluation

TEST SITE AND SOIL CONDITIONS
Based on a seabed soil survey a test location (B) was selected at a water depth of about 300 m, as seen in Fig. 1. The exact test positions and points of soil sampling are shown in Fig. 2. The geotechnical data of the seabed soil are presented in Fig. 3, which shows that the upper 8 m or more consists of normally consolidated clay of high plasticity (CH) with some organic content and an undrained shear strength increasing from about 2.5 to about 12.5 kN/m2 with depth. The indicated further linear increase is from borings for other projects in the Trench.

TEST ANCHORS
Four types of anchor were tested: Stevin, Flipper-Delta, Bruce Mark 2 and Baldt stockless, as Shown in Fig. 4. An instrument box (165x200x1860 mm) was welded to the upper side of the anchor shank, and small brackets for a soil sampler were welded on the anchor fluke. The total mass of each anchor was 3750 kg (3.75 metric tons) including the instrument box. 2 The fluke area ranged from 1.0 m2 for the Baldt anchor to 3.6 m for the Stevin. All anchors except the Bruce were hinged.
Improvements to Frequency-Domain Riser Programs
Authors: Mclver D.S. , Lunn T.S. 
Published: October 2008

ABSTRACT
This paper develops and demonstrates the improvements to frequency domain riser analysis obtained by including a wave surface correction and by calculating forces at the displaced riser position. The range of validity is extended to higher waves without a significant increase in program running costs.
Comparisons of running costs and results are made against two time domain programs. Significant improvements to the bending moment range are obtained and therefore to the fatigue damage estimates for regular waves.

INTRODUCTION
Frequency-domain riser programs are now firmly established as important riser design tools. Their merit lies in their very much lower solution costs compared with time-domain programs while still offering an acceptable degree of accuracy.
The time-domain solution of the idealised riser problem is clearly the more accurate method. Its cost, although large for regular waves, is acceptable provided only a limited number of cases are being considered. However, for a fatigue ana1ys is either a 1arge number of regu1 are wave solutions are required or the response to a synthesized irregular wave must be obtained. The cost can be prohibitive using a time-domain program.
The frequency-domain method seeks directly, in closed form, the periodic solution to which the time-domain program converges after allowing for the decay of the starting transients. Because of the quasi-1inearisation, an iterative solution is required. The most powerful non-linearity is the relative velocity squared term of the viscous drag. If the approximation to this is not chosen with care, large inaccuracies can resu1tl. In their state-of-the art paper Krolikowski and Gay l rationalise the process of carrying out this 1inearisation using the Describing Function technique. Four specific wave inputs are considered:Regular waveRegular wave with currentRandom waveRandom wave with current.
Extremely good and consistent results are obtained when compared with those of a time-domain program. However, the only non-linear term considered is that of drag. The aim of this paper is to show the improvements obtained by introducing the other non-1inearising features of the problem commonly included in a time-domain analysis. These areWave forces which are calculated at the displaced position of the riser.Allowance for the alternate submergence and emergence of the riser in the region of the wave surface.
The technique of dealing with stroke- or rate-dependent tensioner effects and the only recently recognised Froude-Krylov curvature term2 is discussed briefly, although not included in the numerical comparisons of this paper.
The additional terms are treated only for regular waves with or without a current. The extension to irregular waves has not yet been completed.

GENERAL EQUATIONS OF RISER MOTION
The general equations of motion of a riser are usually formulated on the basis of displacements which are small relative to the length of the riser and deformations which are sufficiently small that the conditions for elastic behaviour are satisfied.
Overview of the Central Cormorant Underwater Manifold Centre Project (1974-1983)
Authors: Bastiaanse Tom , Liles J.R. 
Published: October 2008

ABSTRACT
The Underwater Manifold Centre (UMC), installed in the Central Cormorant field of the North Sea in 1982, is an example of a development that extends frontiers in the area of subsea technology. This paper describes the history of the project and how the combined resources of Shell and Esso brought it to fruition.
Topics discussed in the paper range from tl.-1 project's terms of reference to installation of the UMC to present status of offshore activities and remaining work.
It concludes with a broad summary of what the UMC experience has provided to both Companies to date.

INTRODUCTION
This paper discusses the Central Cormorant Project, in general terms, from its early history to its present status, through to future plans to complete the last of its ten wells. The intention of the paper is to set the stage for four more specialised papers on the UMC, which are also being presented at this conference. These companion papers cover the UMC's design, landtest programme, control system, and insulated pipelines, respectively.
The overall Central Cormorant subsea production system concept is illustrated in Figure 1. The system's basic components consist of:The UMCFacilities on the South Cormorant 'A' platform from which the entire system is controlledSatellite wells tied-back to the UMC, including a special satellite well linked directly to the platformAn overhead drilling rig, andPipelines and control lines that link the system together
Maintenance of the UMC can be accomplished from an overhead vessel or by the use of a unique Remote Maintenance Vehicle (RMV) as illustrated in Figure 2.
The system has Through Flowline (TFL) well serv1c1ng capability and is also capable of injecting chemicals to prevent hydrate formation.
The project's budget is approximately £360 million. From its inception in late 1974 to its projected completion in 1986, over 12 years and 600 man-years of Shell and Esso engineering effort will have been expended.

PROJECT HISTORY: 1974-1982
In late 1974 Shell and Esso formed the Joint Underwater Development Team (JUDT) with the objective of developing an underwater production system suitable for use in the hostile environment of the northern North Sea. The team's initial task was to determine whether available subsea technology existed for this application.
This survey indicated that adequate technology and experience could be made available; mainly as a result of Shell's experience with subsea wells in Brunei and elsewhere and Exxon's experience with their pilot Submerged Production System (SPS) project in the Gulf of Mexico #.
The basic philosophy for the JUDT was to use, as far as possible, proven technology in developing a design that emphasised safety, reliability, flexibility, and ease of maintenance. Not unexpectedly, prior systems did not wholly meet North Sea project criteria, so in-depth screening studies were undertaken by a team composed of technical and managerial personnel from both Companies. This background work took until the middle of 1976.
Side Launch of the Lena Guyed Tower Jacket
Authors: Flood J.K. , Pichini P.O. , Danaczko M.A. , Greiner W.L. 
Published: October 2008

ABSTRACT
The launch of the 27,000-ton Lena jacket was a critical and challenging aspect of the Lena Guyed Tower installation. The Lena jacket was the longest one-piece jacket ever launched, and is the industry'sfirst side launch of a major offshore structure. Although the side launch offered advantages over a conventional end launch, this technique presented unique problems that required extensive analysis and innovative solutions. In addition to requiring significant launch barge modifications, the side launch increased the potential for jacket skewing relative to the barge due to differential friction and caused higher-than normal slamming loads due to high entry velocities.
This paper discusses the challenges that were faced and the solutions that were developed. Computer analyses and scale model launch tests are also discussed. Particular emphasis is placed on the jacket skewing solution which utilized a special release system similar to that used in the Space Shuttle Program.

INTRODUCTION
Figure 1 depicts the Lena guyed tower jacket on the launch barge. The 1079-foot jacket rested on four transverse skidways on the 580-foot long by 580-foot wide launch barge and overhung the stern and bow of the barge by 194 feet and 305 feet, respectively. As shown in Figure 1 the jacket was offset 20 feet from the barge center line during the transportation and pre-launch operations.
A two-step sequence of the side launch is depicted in Figure 2. The upper diagram shows the barge ballasted to a predetermined starboard heel angle of 7 degrees. At launch, the jacket was freed from the holdback, release mechanisms and began sliding toward the starboard side of the barge. The jacket slid approximately 60 feet, as shown in the lower diagram, before the jacket's center of gravity passed over the tilt pins of the four starboard tilt beams. At this point the tilt beams rotated, and the jacket slid off the tilt beams into the water.
The side and conventional end launch methods were investigated and compared using extel1sive computer analyses the results of which indicated that both methods were feasible. However, the side launch method was selected because it offered several advantages.The side launch saved approximately 3000 tons of structural steel that would have been necessary to sustain the cantilevered loads experienced in an end launch.Because of this reduced weight, the eight main pile 1060-foot lead sections were preinstalled, which reduced offshore installation time.The risk of damage to the jacket and or barge was minimized during the side launch because the time of exposure to winds, seas, and currents was substantially reduced. The duration of the side launch was less than to seconds as compared with 40 seconds for an end launch.