bluuebunny/crossref_metadata_2025_split huggingface dataset:
Critical Plastic Bucking Parameter for Tubing in Bending Under Axial Tension
Authors: Wilhoit J.C. , Merwin J.E. 
Published: October 2008

INTRODUCTION
Buckling of tubing with moderate diameter to thickness ratios subjected to pure bending, does not take place in the elastic range but occurs by local rippling on the compressive side of the tubing after yielding has taken place. A recent paper by Wilhoit, Merwin, and Jirsa (1) presents a theoretical method of predicting the curvature and wave length at buckling in the plastic range for pure bending and compares theoretical results with previously measured experimental results for full sized pipe. This paper builds upon a solution by Gerard (2) for plastic yielding of thin-walled cylinders in compression using the Ramberg-Osgood (3) representation of the stress -strain curve in pure tension. Wilhoit and Merwin (4) extended a procedure developed by Ades (5) to predict the moment- curvature relationship in both the elastic and plastic ranges for tubes subjected to bending plus axial tension.
The present paper extends the theoretical results of reference (1) to the case of bending with axial tension by using the technique developed in reference (4). Since reference (1) bases buckling on a critical strain on the compressive side of the tubing, it was only necessary to use the method of reference (4) for each case investigated to find the curvature corresponding to the critical strain.
Thin walled welded steel tubing 2½ inches in diameter with diameter to thickness ratios from 35 to 83 were tested in a loading frame built to allow a bending load to be superimposed on an axial tensile load. Theoretical and experimental results are compared.

TEST SPECIMENS
All test specimens were obtained from round welded mechanical tubing MT-1010/202½ inches in diameter with nominal thickness 0.065 and 0.049 inches. Test specimens approximately 20 5/8 inches long were cut to fit into the loading frame. From the 0.048 inch tubing (the actual thickness of the 0.049 inch nominal thickness tubing was 0.048 inches while the actual thickness of the 0.065 nominal thickness tubing was 0.069 inches), specimens with average thickness of 0.036 inches and 0.029 inches were machined.
In order to make these thicknesses of 0.036 inches and 0.029 inches more nearly uniform eight inch lengths of the .048 inch tubing were inserted into special mandrels and then machined to size. These turned down lengths were then welded to.048 inch tubing end pieces to form the test specimen. Thicknesses were still found to vary considerably for these turned down specimens and average thicknesses after testing were ultimately used. It should be noted that tubing of 0.069 inch thickness was used for three tests while tubing originally of thickness 0.048 inch was used for the other nine tests.
Implementation of IOR Technologies
Authors: Kjorholt H. , Utseth R.H. , Strom S. 
Published: October 2008

Abstract
Statoil's ambition is to recover 55% of the STOOIP from subsea fields. To obtain this, extensive R&D efforts are required on all technology areas involved. Statoil's policy has been to establish strategic research partnerships with major suppliers and service companies, ideally with a 50/50 cost split between the parties. The partner selection process has normally been based on combined tender and architect competition, with a broad range of selection criteria.
Implementation of the new technology is secured as far as possible by early commitments from the potential users among our assets. The users are also kept involved in all phases of the project, on an engineering level as well as on the management level. This both helps ensure the project is heading in the right direction and makes people responsible for implementation familiar with the new technology.
Statoil subsea R&D efforts have already led to significant results. Several technologies are now being taken into operation according to plan. The most important being:A new ship for low cost subsea intervention (USD 150 000 per day) is in orderEquipment for subsea low cost TTRD sidetracks (USD 10 mill per drainage point) is ready for operation autumn 2007A complete subsea process plant is under installation in the Tordis field and will be in operation before the end of the year

Introduction
Comparing the present ultimate oil recovery of subsea fields with fields based on dry wellheads we see a significant difference in favor of dry wellheads. For Statoil operated offshore oil fields the average recovery levels are close to 45% and 60%, respectively. Even though these numbers are high in comparison with a world wide average, the ambition is to increase the recovery by another 10% points (Ref. 1). In Statoil's effort to reach this ambition the R&D portfolio addresses all the relevant technology areas. The different focus areas are:Ability to identify more accurate where the oil is located and its volumeImprove modelling of the production process and thereby the production strategyReduce cost of well construction and well interventionReduce cost and increase flexibility of subsea InstallationQualify pumps, compressors and other process equipment for sea bed installationImprove sensor technology, data transmission and data handling in order to make improved decisions
There are no obvious inherent factors like reservoir properties or drilling challenges responsible for the gap in recovery between subsea and platform developments; it is solely a consequence of the economic reality operating subsea versus from a fixed installation. Our experience is that, all other parameters the same, recovery is a function of reservoir infrastructure (i.e. total number or density of drainage/injection points during the life of the field), access to well intervention and ability to minimize the wellhead pressure. Today the cost of a subsea well, all infrastructure included, is in the range 4-6 times the cost of a platform well.
On the Jackup Platform In the North Sea
Authors: Corder Paul R. 
Published: October 2008

Abstract
The adaptability of the jackup drilling platform to the severe environment of the North Sea requires knowledge of its capabilities both Afloat and while standing on location. Through extensive computer analysis, this paper surveys the drilling mode strength envelope of a Marathon LeTourneau type jackup platform. The results form a family of curves which express acceptable combinations of water depth, wave height, wave period, and wind speed for given air gap, storm direction, and current.

1. Introduction
The jackup platform can be designed to operate in the North Sea. While this statement is partially supported by the presence of several jackup platforms in that demanding environment, the limits of these platforms' capabilities need precise definition. Such definition involves multiple disciplines, including naval architecture, materials, and structures among others. This paper concentrates on the structural aspect of jackup platform design and analysis. More specifically, it attends to computer structural modeling techniques and a procedure to provide meaningful data about the standing-on-1ocation strength envelope of a mobile self-elevating offshore drilling platform.
The Marathon LeTourneau type jackup platform is roughly triangular in plan with three legs which may be either triangular or square in cross-section. These legs are open space frames consisting of tubular bracing members and chords of circular or built-up cross-section. Built into each chord are continuous racks which engage electrically driven pinions located in a substructure above the top deck level. These independent electric motors elevate and lower the platform at a rate of 90 feet an hour.
The computerized analysis for determining leg stress levels under various combinations of storm loads requires a mathematical model to simulate the real platform, a definition of the loads on this computer model, and finally a suitable structural analysis computer program. There are many ways to develop an analysis sequence. This paper outlines one approach. For simplicity, only the elevated condition during a simulated storm from 60° off the bow is considered.

2. Statement of Structural Modeling Approach
Analysis of the storm response of a mobile self-elevating offshore drilling platform (nonmat supported) leads one to the conclusion that the portion of the leg within and near the hull is the strength critical portion. Consequently, the philosophy underlying the mathematical modeling of the jackup platform outlined below seeks to simulate accurately the hull-leg interaction. This is accomplished by using a three dimensional beam element model of the platform of sufficient complexity to appraise the actual storm response of the platform. It is noted that any calculated results, whether by slide rule, desk calculator, or large digital computer, are only as good as the assumptions forming the basis of the calculation. Hence, computerized calculations must provide answers which reflect experience and are not just the results of an abstract computation.
Combined Tow Method for Deepwater Pipeline and Riser Installation
Authors: Hellestø Alf Roger , Karunakaran Daniel , Gryttena Trond , Gudmestad Ove Tobias 
Published: October 2008

Abstract
During the last years the number of deepwater oil field developments has increased significantly, resulting in a strong demand for pipe lay vessels. The continuously increasing dayrates of lay vessels is making the combined tow method for deepwater pipelines and riser more competitive. Also a requirement for more sophisticated materials and strict qualification requirements to welded joints, due to sour service and fatigue performance, make the tow method a more preferred solution since the pipeline is fabricated and welded onshore. More than 50 bundles have been installed in the North Sea towed out from the Wick fabrications site located in the northeast of Scotland.
This paper describes a method of towing deep water pipelines and risers, fulfilling both strength and fatigue requirements. The concept incorporates presently available equipment and technology. The proposed method is demonstrated through two case studies presenting the installation of a gas export pipeline at a water depth of 800m and a riser/pipeline string at a water depth of 300m.

Introduction
Pipelines may be installed by the towing techniques where long sections of the line are made up onshore and towed with tug boats to the field. The design procedures for towed or pulled lines are very dependent on the type of tow method chosen. It is also important to control the submerged weight of a towed line to minimize towing forces and at the same time have sufficient weight for stability on the seabed in cross currents.
The combined tow concept reported in this paper incorporate the following tow methods for deep water pipelines and risers:
Figure 1 Controlled depth tow method (available in full paper)The off-bottom tow method (with buoyancy tanks and chains) from the fabrication site to approximately 5km offshore.The CDTM (Controlled Depth Tow Method, Figure 1) from 5km offshore to a temporary location where the buoyancy tanks are removed.The catenary tow method for the deep water tow to the installation site (without buoyancy tanks and chains).
For the off-bottom- and controlled depth tow method, buoyancy steel tanks are mounted at selected intervals. Chains are also mounted at frequent intervals along the pipeline to overcome the excess buoyancy and keep the system stable. During the catenary tow method the buoyancy modules and chains are removed and the submerged weight of the system increases.

Tow Methods
In order to use the tow methods, the pipeline is normally constructed at an onshore site with access to the sea. Once the pipeline sections are welded together to a determined length and hydro tested, the pipe is de-watered and launched into the water by a tow vessel attached to the lead end as seen in Figure 2. Onsite winches are attached to the trail end to ensure back tension and control the launch speed.
Design Aspects of Platform for a Floating Nuclear Plant
Authors: Dotson C. , Anderson R.S. 
Published: October 2008

ABSTRACT
Tenneco and Westinghouse Corporations formed a joint venture in May, 1972, designated Offshore Power Systems, to market, design and manufacture standard nuclear power plants for offshore installation. The plant design is a totally integrated nuclear generating station, mounted on a floating platform and moored within a protective breakwater. The plant is standardized such that it can be sited along the East and Gulf Coasts of the United States. This paper discusses the design of the platform which serves as the foundation for the Floating Nuclear Plant.

INTRODUCTION
The concept of offshore siting of nuclear power plants is not new; studies and investigations in this area date back to at least the mid-sixties. Although studies concluded that the concept offered some advantages, in depth studies were not conducted to fully determine that the concept was both technically and economically feasible.
The worsening trends in finding suitable land sites along the coast, power plant cost escalation and schedule delays, the growing concern of environmental impact, and a desire for standardization to facilitate the licensing process have all lent impetus to a serious look at offshore siting.
The Special Project Division of Westinghouse was created in April, 1971, to devote fu11time effort to a technical and economic study of the power plant and a manufacturing facility. They were joined by approximately forty five employees from Newport News Shipbuilding, a Tenneco subsidiary, in the summer of 1971. The results of the study led to the formation of a joint venture designated Offshore Power Systems located in Jacksonville, Florida, and the signing of a contract for two units with Public Service Electric and Gas Company of New Jersey.
Both the nuclear power plant and its supporting platform utilize existing and proven technology. Plant components and systems are nearly identical with those of comparable licensed land plants. The nuclear steam supply system is a typical Westinghouse four-loop 3425-MWt pressurized water reactor with ice condenser containment. Figure 1 is a sectional view of the plant through the containment. The power generation plant contains a standard Westinghouse turbine generator unit with a net output of 1150 MWe. Thus, the only real innovation in power plant design is the platform which will be moored in a protective basin.

PLATFORM STRUCTURE
The platform is approximately 400 feet long, 378 feet wide and 40 feet deep with a plant displacement of about 150,000 short tons. Full depth bulkheads run in both the longitudinal and transverse directions extending the length and width of the platform to form a grid. Along the 378 foot width bulkheads are located at regular intervals of 37 feet; 9 inches. Along the 400 foot length bulkhead spacing varies from approximately 47 feet to 82 feet.
Wrong Paradigms in the Actual Well Testing Analysis - Oil Reservoir Case
Authors: Medina R. A. 
Published: October 2008

Abstract
At first, four misconceptions found in the current state-of-art of the oil well testing are revised in detail in this paper. A mathematical demonstration, a historical review and a field example are presented to support these four technical observations: (1) The wrong use of the volumetric factor B in the actual pseudosteady-state flow equations. (2) The use of semi-empirical correlations, like those of Vogel, Fetkovich or Wiggins, to analyze IPR curves. (3) The calculation of the maximum oil flow rate potential of a well at a wellbore pressure of zero. (4) The historically rooted paradigm of underestimating the Deliverability Tests capacity to determine reservoir properties.
Then, the revision of these four wrong paradigms conveys to the introduction of a new approach for obtaining reservoir information: the “Productivity State Analysis”. The most promissory feature of this new Well Testing approach is the opportunity that it opens to obtain the information through tubinghead pressures measurements.
Finally, two ambitious applications of these surface tests for the industry are proposed: (a) the pre- and post- evaluation of every workover/stimulation job, and (b) the periodic Productivity-State-Analysis of reservoirs. This last kind of reservoir evaluation could both improve dramatically our actual understanding of their complex dynamic reality and give us an index value for our efficiency in producing from them.

Introduction
To improve the efficiency in both the production of the wells and the exploitation of the reservoirs, it is indispensable to obtain opportune key-information about them. In this paper, after the discussion of four technical observations to the current Well Testing state-of-art, a new Well Testing approach is presented to determine key well-reservoir information from tubinghead measurements, which means low-cost tests and the opportunity to evaluate greater amounts of wells.
Seafloor Scour Protection for a Semi-Submersible Drilling Rig on the Nova Scotian Shelf
Authors: Wilson N.D. , Abel W.D. 
Published: October 2008

ABSTRACT
Protection against scour became a prime consideration when it was proposed to set the Sedco H semi-submersible drilling rig on the seafloor in 90 feet of water to drill an exploratory well on the Nova Scotian Shelf. It was expected that ocean current velocities adjacent to the 80-foot diameter pontoons of the Sedco H would be accelerated significantly to cause scour of the sandy bottom around the pontoons and endanger the stability of the rig.
Laboratory model experiments were conducted and the results confirmed that scour would occur if no protection were used. Further experiments were then conducted to determine the rate of scour and the amount of protection that would be required to prevent scour. After several model test runs, it was determined that scour protection extending 50 feet from the edge of each pontoon would be required. An inexpensive nylon mesh material was chosen as the protection material to be laid as a.mat on the ocean floor.
On-site experiments prior to the arrival of the rig were performed to develop working techniques and methods of placing the 7500 square of material required for the installation. Sample strips of the nylon mesh were installed by divers to evaluate its sand retention ability and handling characteristics at the varying current velocities. Based on the results of the on-site work, the nylon material was prepared for efficient underwater handling and a program was developed for fastening it to the ocean floor using steel pins and sandbags.
During drilling of the well, regular inspections were conducted to monitor the mat installation. Further verification of the laboratory prediction of the scour was made by removing small strips of the mat at one of the pontoons and monitoring the rate and amount of scour. It was found that oscillating currents induced by waves had a larger influence in causing scour than did tidal currents.

INTRODUCTION
Scour protection is often required to prevent scour from occurring around marine structures. This was the case when it was proposed to set the semi-submersible drilling rig Sedco H on the seafloor to drill the Mobi1-Tetco Thebaud P-84 well in 90 feet of water six miles southwest of Sable Island during the summer of 1972. Figure 1 shows the location of the well.
Normal tidal currents in the area reach a maximum of about 1.5 knots (0.77 metres/sec.). Scour was expected since it was known that the seafloor was fine sand and that the 80-foot diameter Sedco H.pontoons would cause the current velocities around the pontoons to be accelerated considerably. However, it was impossible to predict theoretically the amount of scour or the amount of scour protection that would be required mainly because the relationship between current velocity, rate of scour, scour depth, and grain size distribution is not yet well defined.
Underreamed Footings Support Offshore Platforms In The North Sea
Authors: Ehlers Clarence J. , Bowles William R. 
Published: October 2008

ABSTRACT
In selecting a foundation element for support of template-type structures in the Ekofisk Field in the North Sea, it was concluded that dense sands and hard clays would limit installation of pipe piles by driving alone to a penetration much less than the required penetration, and that installation problems and design uncertainties made a grouted insert pipe pile marginally desirable. Phillips Petroleum Company originated the idea of using an underreamed footing excavated beneath a driven pipe pile in a stratum of hard clay at about 100-ft penetration below the seafloor. Analysis of the underreamed footing from both technical and construction standpoints indicates that the use of this type of foundation element is feasible.
Two platforms are now supported in 230 ft of water on a total of 36 underreamed footings with base diameters ranging from 9 to 14 ft. The underreamed footings were installed using rotary drilling equipment supported on a temporary working deck placed on the substructure or jacket. No major problems were-encountered during construction.

INTRODUCTION
A giant oil and gas strike, designated as the Ekofisk Field, was made in the North Sea in 1969 by Phillips Petroleum Company. The Ekofisk Field is located in the Norwegian Sector of the North Sea in Block 2/4 as shown on Fig. 1 and is approximately 190 miles south-southeast of Stavanger, Norway. In the second phase of development of the Ekofisk Field, 11 offshore structures are being installed consisting of two isolated drilling platforms and nine interconnected structures, designated Complex "C". The structures of Complex "C" are connected by a bridge system and are aligned so that the total length of the complex is in excess of one-half mile. From north to south, the structures in Complex "C" consist of a one-million barrel storage tank, a pipeline pump station platform, a bridge support structure, reinjection drilling platform, personnel quarters platform, field terminal-production platform, two bridge support structures and a flare support structure. With exception of the storage tank, all structures in the Ekofisk complex are conventional template-type structures. The one-million barrel storage tank is a unique offshore storage structure that is constructed from reinforced concrete and supported on a mat foundation bearing on the seafloor.
Foundation borings drilled at Ekofisk disclosed the presence of strong foundation soils consisting of dense sands and hard clays. The foundation element given first consideration for support of the template-type structures at Ekofisk was a driven 42-in.-OD open-end pipe pile, which is the conventional foundation element for offshore structures. Static pile capacity computations indicated that 42-in.-OD pipe piles would have to be driven to penetrations in the order of 350 ft below the seafloor to support the maximum design compressive loads of 4500 kips.