bluuebunny/crossref_metadata_2025_split huggingface dataset:
Centrifuge Modelling And Parametric Analyses Of Drag Anchor Behavior
Authors: Dunnavant T.W. , Kwan C-T.T. 
Published: October 2008

ABSTRACT
A centrifuge and analytical modelling study was performed to gain new insight into the behavior of drag anchors in more-or-less normally consolidated clay soils. The conditions investigated are pertinent to deep-water MODUs and FPSS in "soft clay" regions such as the Gulf of Mexico. The study results show that soil shear strength gradient and lead line type (wire rope vs. chain) significantly impact anchor capacity. Cyclic loading and soil consolidation (anchor soaking) are of lesser importance. Also, it was found that modern, high-capacity drag anchors can provide significant resistance to vertical upIift in soft clay. Standard industry guidelines for predicting anchor capacity do not consider lead line type or soil shear strength gradient and do not permit vertical loads on anchors. It is recommended that anchor sizing guidelines be modified in light of this studyâ??s results.

INTRODUCTION
Existing industry procedures for predicting the capacity of drag anchors [1,2] are based in large part upon the results of field tests performed by the U. S. Navy [3]. These (and other) results have been used to develop empirical charts that relate anchor weight to anchor holding capacity. These charts have some limitations when applied to sizing anchors, particularly those for deep-water moorings:The anchors needed for deep-water mobile offshore drilling units and floating production systems commonly weigh 15 to 80 kips, while the design curves are based primarily upon tests of anchors that weighed 0.5 to 6 kips. Extrapolation therefore is a source of uncertainty.The tests used to develop the curves were performed at a limited number of sites. As a result, the curves are for use in generic soil types such as "soft clay", "sand", and "stiff clay". Site-specific conditions may not be properly addressed.Since the standard curves are based on historical test data, they may not reflect the performance characteristics of new anchor types or enhanced versions of older anchor types.The standard design curves have been developed using short-duration tests in which the anchors were subjected to monotonically increasing loads. Other conditions of potential importance, such as cyclic loading and the period of anchor embedment, generally have not been addressed.
The work reported here was a study of the performance of two types of modern drag anchor in soft clay. The study investigated how anchor capacity is influenced by anchor size, soil shear strength gradient, cyclic loading, anchor soaking, and lead line type (wire rope vs. chain). It included the first tests of properly scaled model drag anchors in a geotechnical centrifuge and limit equilibrium analyses. The results showed, first, that these methods can be used successfully to investigate the behavior of very large anchors in soft clays. Second, the results revealed the significant impact that soil shear strength gradient and lead line type have on anchor capacity.
Zeepipe North Sea Pipeline Welding
Authors: Laing B.S. 
Published: October 2008

ABSTRACT
Statoil's Zeepipe Transportation System under construction is the largest offshore pipeline project ever. The completed system will bring natural gas from the Sleipner and Troll fields in the North Sea to Zeebrugge, Belgium, for onward distribution to customers in mainland Europe. Phase f of the project involved the construction of 1075 km of offshore pipeline including 809 km of 1016-mmdiametefi 24.2-mm-wall pipe. These pipelines were laid in 1991-7992 by European Marine Contractors Ltd. (EMC) off the Semac I and Castori Sei Iaybarges.
The Semac I used the CRC-Evans Automatic Welding system for welding 617 km of the tO16-mm pipe. The welding procedure was developed and qualified at the CRC-Evans facility in Houston, Texas, and the procedure was requalified aboard the Semac 1.
Initially, the mainline welding with the CRC-Evans' system was, on single, 72.2-mm-lengths of pipe because the double joint system was inoperative. However, the majority of the pipe was double jointed on the Semac I and mainline welding with CRC-Evans was on the double- -jointed pipe. The lay rates on Semac I were outstanding, averaging 2.5 km/day for the 199f season and 2.8 km/day for the 1992 season. Peak daily production was 4. 1 km.

DESCRIPTION OF PROJECT
The Zeepipe Transportation System is being developed by Statoil for treatment and transport of natural gas from the Sleipner and Troll fields in the North Sea to Zeebrugge, Belgium, for onward distribution to customers in mainland Europe. The project is divided into three phases:Phase 1 is intended to bring gas from Sleipner "W and the 16/11S platform down to Zeebrugge by 1993, and to install a condensate pipeline from Sleipner "A" to Kalsto in Norway.Phase 2 will tie the Troll field into the system, and will be in operation in 1996.Phase 3 will consist of potential compression facilities at locations to be defined along the pipeline.
The contractor for the Phase 1 work is European Marine Contractors Ltd. (EMC). EMC was responsible for installing the following Zeepipe pipelines:807 km (501 miles) of 1016-mm (40-in)diameter.API 5LX-65 (modified) pipe from me Sleipner platform to Zeebrugge.1.5 km (0.9 miles) of 1016-mm-diameter API 5LX- 65 (modified) stub at the Sleipner platform.39 km (24 miles) of 762-mm (30-inch)-diameter API 5LX-65 (modified) pipe from Sleipner to 16/11S platform.227 km (141 miles) of 508-mm (20-inch)-diameter API 5LX-60 condensate pipe from Sleipner to Kalsto, Norway.
The major marine pipeline construction was done with EMTs two, semi-submersible lay barges, Semac 1 and Castoro Sei. The flat-bottom laybarge, Castoro Due, was used for the beachpull at Zeebrugge and 18 km of the mainline northward from Zeebrugge and crossing the Scheur Channel. The Semac I laid 617 km (383 miles) of the 1016-mm-diameter pipe during 1991–1992 seasons. The Castoro Sei laid 192 km (119 miles) of the 1016-mmdiameter pipe, the 39 km of 762-mm-diameter pipe, and the 227 km of 508-mm pipe.
Development Of Light-Weight Flexible Riser Pipe
Authors: Makino Yoshiyuki , Ishii Kenichi , Fuku Tadashi , Morimoto Satoru , Wada Hiroyuki 
Published: October 2008

Abstract
Light-weight flexible pipe is needed for deep-water offshore oil fields, but there is a limit to the depth at which conventional flexible riser pipe can be used. In this paper we first describe the concept of the limits of applicability for conventional flexible riser pipe and discuss trends in and methods for making it lighter-weight. Then, because the use of fiber reinforced plastic (FRP) for the tensile reinforcing layer is considered the most effective and practical way to lower the weight of pipe, we discuss the conditions and characteristics for FRP for use in the reinforcing layer of FRP riser pipe, as well as the design, manufacturing, and evaluation of FRP riser pipe.

Introduction
As shown in Figure 1, flexible riser pipe consists of an interlocked conduit, an inner plastic pipe, hoop stress reinforcement, tensile reinforcing layer, and an external sheath.1')2)3) Such pipe has come to be widely used in offshore oil fields, where it has become an essential item. As deeper offshore oil fields are developed, this pipe is being used at greater depths. By 1992 oil fields laying 850 m underwater are under developments) and the future is expected to bring the development of offshore oil fields at even greater water depths. Weight is an important factor in floating production systems, and research and development is being carried out in order to create lighter-weight TLP tethers and rigid risers.4)
The use of flexible riser pipe in such deep-water oil fields causes problems of increased laying tension and increased side wall pressure due to the weight of the itself. This has led to the development of methods for installation at great depth5)6and the development of lighter-weight flexible riser pipe.7) Study is underway for replacing the reinforcing layer of light-weight flexible riser pipe with aluminum or a composite material (FRP). Meanwhile, the use of stronger reinforcing steel and the use of FRP are being considered to solve this problem, and this paper discusses the use of FRP.

Key problems
The depth at which flexible riser pipe can be used is limited by the allowable tension and the laying side wall pressure, which depend on the weight of the pipe itself. As shown in Figure 1, flexible riser pipe has a structure in which a plastic pipe is reinforced by multiple layers of metal. The greater the depth at which the pipe is to be used, the greater its weight must be, and therefore the thicker its tensile reinforcing layer must be, but this produces even greater weight, requiring even greater thickness, in a vicious cycle that imposes design limits.
To ascertain the characteristics of the tension of flexible riser pipe in the depths of the ocean, we analyzed the fluctuations in tension produced by waves in a free hanging configuration. Here we considered the maximum static movement assumed for a semi submersible platform and the dynamic response for a significant wave height of 18 m and a period of 15 see, while the pipe is subjected to the use pressure.
Motion And Impact Responses Of Jackups Moving Onto Location
Authors: Miller B.L. , Frieze P.A. , Lai P.S.K. , Lewis T.C. , Smith I.A.A. 
Published: October 2008

ABSTRACT
The objectives and proposed approach for a joint industry study to investigate the problems associated with jack-ups manoeuvring on and off location are described. The study involves assessments of appropriate wave statistics, jack-up motions, seabed response, dynamic impact analyses, and structural evacuation. The results are expected to be harnessed through an on-board PC-based unit.
Results are reported from the motions analyses, soil-structure interaction, end 2-D impacts of the forward leg of a widely used rig onto clay, sand and rock. Conclusions drawn from these individual studies are presented together with a summary of progress on the remaining parts of the project.

INTRODUCTION
Currently, the responsibility for deciding whether or not to move a jack-up onto or off a particular location is taken by the drilling contactor's marine supervisor on board the rig. Undoubtedly, in reaching a decision, the opinions of the barge engineer, tool pusher, operator representative and marine surveyor are all taken into consideration. The decision is based on the practical experience of the personnel and on the limited technical guidance given in the operating manual.
Typically, the operating manual states that the limiting environmental condition is a 5 ft sea. A critical roll/pitch motion curve is sometimes given as a function of water depth. Such a curve is of little use when moving off location. It is also of limited use when moving onto location since it ignores other environmental factors such as current and wind but, more particularly, takes no account of the nature of the seabed, nor of any heave motion. Clearly, different consequences for the rig will result from moving onto soft clay compared with dense sand and hard clay. Touching down on rock will be even more onerous but this aspect is ignored completely in the advice formally offered to the supervisor.
The reason for providing advice when moving onto and off Iocatlon is to minimize the possibility of damage occurring to the legs or jack-houses. Structural damage can occur to these in the event of an unexpectedly severe touch-down.
In an effort to provide more appropriate guidance in such circumstances, the joint industry project described in the next section was initiated. It is now complete although only part of the results can be presented at this time. The study is being complemented by a further investigation concerned with jack- UPS manoeuvring onto and off location in close proximity to a fixed installation. This is receiving separate funding but the results from both studies will be exchanged.

OBJECTIVES AND PROCEDURE
The basic criterion which is to be satisfied is that the risk of exceeding the structural capability of any part of the rig during initial touch-down or lift-off is not unacceptably high. To satisfy this criterion objectively, it is necessary to model these events in some detail. The elements of the approach are illustrated in Fig. 1 and are as follows.
Criteria For Dent Acceptability In Offshore Pipeline
Authors: Fowler J.R. 
Published: October 2008

ABSTRACT
This paper discusses testing and analysis work done to establish the effects of pipeline dents (without gouges) under cyclic internal pressure loading. Operators were surveyed regarding the expected dent shapes and failures from dents that had been experienced. A full scale test program utilizing 12-3/4" pipe with controlled dents and cyclic pressure was carried out. Elastic and plastic finite element analyses was used to determine stresses so that a fatigue analysis could be done.
The results indicate that plain smooth dents less than 5% of the diameter for pipe with a diameter to thickness of less than 30 are not a problem for normal pipeline service. Plain dents are probably not a concern for normal gas line service. An analytical procedure was developed to predict the fatigue life of a pipeline subjected to a combination of plain dents and cyclic pressure.

INTRODUCTION
Extensive research has provided an understanding in the behavior of pipelines subjected to mechanical damage [2–111, The presence of a gouge or the combination of a gouge and a dent has been proven detrimental to the burst strength of pipelines [2–91. The research has also revealed that plain smooth dents, in the absence of a defect, do not significantly reduce the burst strength of pipelines [5,7,8,91. On the other hand, plain dents locally increase the pipe stress due to pressure, Thus, fatigue failures from dents can occur from normal operating pressure fluctuations in the lines over a period of time [7].
The purpose of this research was to develop an understanding of the effects of plain dents subjected to cyclic pressure such that guidelines can be provided which tell operators:Which dents should be repaired immediately?Which dents are of no concern?Which dents could be tolerated for a definable period of time with perhaps a lowered operating pressure?
The main goals of this project were:Review of past failures through historical data [10,12, 13] and published works [2-9,11] to determine the general shapes of the most common dents, and the general operating pressure variations which gas and oil lines experience. From this a "specification" for a typical dent was developed.Conduct experiments to measure fatigue lives of dented pipelines.Predict the stress level and therefore the fatigue life as a function of all relevant variables using the finite element method.

EVALUATION OF EXISTING DATA
One of the objectives of this task was to find specific data regarding failure situations such as dent size and shape, pipeline size, thickness and grade, the operating pressure history of the line, a description of the failure and any special circumstances of the failure. Other data that is necessary for fatigue analysis purposes is the tropical cyclic pressure variations (amplitude and frequency) of both oil and gas pipelines, The sources reviewed were.
Super Stainless Steels: Review Of Norwegian Offshore Practice
Authors: LØvland Paul 
Published: October 2008

ABSTRACT
In the 80's there has been a quiet revolution regarding steels offshore Norway. Duplex stainless steel (type 2205) was installed in hydrocarbon systems (together with AISI 3161 and carbon steel). Highly alloyed austenitic stainless steels (type 6 Mo) were applied primarily in seawater-containing fluids (together with cupronickel). A small amount of highly alloyed duplex steel (super duplex) was used e.g. in a process system.
The reason for this development was expected lower total life-time costs for the oil/gas production, due to improved corrosion resistance of the new steels.
In the 90's it is presumed that titanium, glass fibre reinforced plastics, and perhaps a new super austenitic grade with increased nitrogen content will take a bigger share of the market for sea water containing fluids.
This paper summarises the Norwegian practice with respect to steel properties, requirements, engineering features, and use, the latter including some elucidation of needed quantities. Finally, a brief outlook to future use and competitive materials is presented.

INTRODUCTION
During the 80's there was a quiet revolution in the North Sea regarding materials for offshore production platforms. It related especially to corrosion resistant steels, i.e. stainless steels. Apart from the well known 18-8M0 steel, AISI 316 L, particularly duplex, super duplex, and super austenitic (6 Mo) were used in lieu of carbon steel and cupro-nickel. The first large-scale application was offshore Norway where significant parts of the process and utility systems - piping and vessels - were made of duplex and 6 Mo steels. Shortly thereafter many British platforms were equipped with equal materials.
The main reason for this development that still goes on, is lower total life-time costs expected with these steels. This again depends on the relatively high maintenance costs on the particular type of platforms installed in the North Sea. One must take into account that carbon steel corrodes quickly and may have to be repaired or replaced several times during the lifetime of the platform.

THE SUPER STAINLESS STEELS

Background
When the converter processes AOD (argon - oxygen - decarburisation) and VOD (vacuum - oxygen - decarburisation) were introduced in the 70's, a revolutionary development of stainless steels started These refining methods resulted in very pure steel, especially with respect to oxygen, sulfur, carbon and slag inclusions; moreover, the methods allowed narrow compositional ranges. In this way it became possible to improve e.g. hot workability, weldability, and corrosion resistance of the steels, and more highly alloyed grades could be produced. The improvements were obtained to reduced costs, e.g. caused by less chromium loss during refining of low-carbon melts. Production costs were further lowered by applying continuous casting techniques. Even foundries have today found benefits by using the methods at least for premelted raw materials, and the most advanced of them have invested in small AOD-converters.
Optimized Well Completion Design in the Statfjord Field,North Sea
Authors: Kostøl Petter , Rasmussen J.H. 
Published: October 2008

ABSTRACT
This paper reviews the experience with the original completion of the Statfjord wells. A brief description of the reservoirs and geology is given and the drainage strategy for each reservoir is reviewed.
The workovers' performed due to reservoir requirements, corrosion, sand production and mechanical failures are summarized.
The design basis for an optimized completion is given and the benefits of the monobore completion are reviewed. A typical Statfjord well life sequence is described and finally some production results are given.

INTRODUCTION
The Statfjord field is located in the North sea 200 km northwest of Bergen, Norway on the boundary between the UK and the Norwegian sector. The field was discovered in 1974 and came on production in 1979. Mobil was responsible for exploration, development and production until January 1st 1987, when Statoil assumed operatorship. Statfjord is the largest oil producing field in Europe with a plateau production of around 120 000 Sm3/d.
The Statfjord field is around 24 km long and 4 km wide and consists of the Upper and Lower Brent, Dunlin and Statfjord reservoirs. The field is developed with three large integrated concrete gravity based platforms.
A total of 108 wells has been drilled to date, where 74 are oil producers, and the rest are water or gas injectors. The production from each well varies from 500 to 7000 Sm3/d. The wells were initially completed with a 7" carbon steel tubing and a diameter restricted tail pipe. Tubing retrievals were in many cases required to recomplete these wells. The restricted tail pipe limited the use of through tubing equipment. Some tubing strings also had to be replaced due to corrosion and leaks.
The completion has now been changed to take the full well life into account and to fit the drainage strategy for the individual reservoirs. The 7" monobore completion allows for reliable low cost recompletion and the use of conventional tools for any through tubing operations.

DRILLING PROGRAM
A total of 108 wells have been drilled on Statfjord to date and 3 redrills have been performed. The maximum deviation was initially limited to 60 degrees, but since 1988, high angle, extended reach and horizontal wells have been drilled. A well status is given in table 1. Initially 12 1/4" hole was drilled to TD and 9 5/8" casing set through the reservoir, but most of the wells are drilled with 8.51' bit through the reservoir with a 7" liner (72 wells). At present all the wells are drilled with 8 1/2" hole through the reservoir.
To meet the zone isolation requirements, the 9 5/8" casing or 7" liner is cemented through the reservoir. Concentrated effort has been put into the cementing of the reservoir sections, especially for the horizontal and extended reach wells. Rotating the liner while cementing has been a key factor in achieving good cement jobs and zone isolation.