bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Field Tests on Prototype of Leg Penetration Monitor System To Avoid the Punch-Through Accidents of Jackup Rigs
Authors: Watanabe Y. 
Published: October 2008

ABSTRACT
Punch-through accidents with offshore jackup drilling rigs could bring on more serious damages than ever as the rigs become larger in size and go toward deeper and severer waters. There has been a pressing demand from the field for systems that minimize the possibility of such accidents.
This paper reports the development and the field tests on the prototype of a Leg Penetration Monitor System (LPMS) which has been conceived to prevent punch-through accidents on jackup drilling rigs, based on the design already described in the previous paper1.
Using prototypes, the following two kinds of field tests were carried out, and the test results confirmed the propriety of the system reported below.
Test (A): Cone penetration and data processing tests
Test (B): Acoustic sensing system tests in measurements of water depth, air gap, coordinates of sea-bottom transducer, leg penetration and small leg displacement.

INTRODUCTION
It is reported that some 20 percent of major jackup rig accidents occurred worldwide have been caused by some sorts of leg troubles, including punch-throughs (P-T) of the footings. Once a P-T happens on a leg, it likely causes damage to the leg structure and/or the associated jacking unit, or it even threatens losses of the rig and life. Particularly, the recent trend toward heavier jackups being built to cope with deeper and harsher seas of operation will translate into more serious consequences once a P-T accident takes place. An effective system, therefore, is vehemently awaited in the field that would possibly predict and provide preventive measures against the occurrence of a P-T accident on a jackup rig, thereby assuring safe drilling and development activities at sea.
The previous paper1 reported the results of a study which finally led to the successful development of two P-T preventive measures. These countermeasures were: Strata Data Monitor System (SDMS) and Vertical Position Monitor System (VPMS). The SDMS allows to precisely know the properties of seabed soil through a device which, mounted on the rig itself, surveys the seabed nearby or immediately beneath the leg footings (spud cans), evaluates the safety of the sea floor on to rest the legs, and even suggests safe preloading procedures by computing the bearing capacity of the site. The VPMS acquires, monitors and records data on the water depth and the vertical position of the platform with respect to the sea floor during the jacking up/down and preloading operations. These two systems altogether are referred to in thispaper as the Leg Penetration Monitor System (LPMS).
Figure 1 shows an outline configuration of the SDMS. Three cone-penetrometers that survey the seabed immediately underneath the leg footings are illustrated in the figure. An outline configuration of the VPMS is presented in Figure 2. Eight acoustic transducers are arranged in their respective locations in the following quantity and at the following known or unknown coordinates.
Soil Reaction to Axially Loaded Piles
Authors: Kagawa T. 
Published: October 2008

ABSTRACT
This paper presents a procedure for constructing the axial load-settlement (t- z and Q-z) relations of a pile driven into normally to lightly overconsolidated clays. The proposed procedure is based on the concept of soil-reaction coefficient ? and the procedure was developed from results of a series of nonlinear finite-element analyses of soil-pile systems with varying soil-pile parameters. The proposed procedure is simple, and it yields the t-z and Q-z responses that are consistent with those from existing methods.

INTRODUCTION
Pile foundations are commonly employed in offshore environments to improve foundation performance. Pile foundations are usually sufficiently stiff against axial loads, and most piles are designed for load-bearing capacities and for lateral deflection criteria only. However, the pile foundations for fixed offshore platforms must resist huge overturning moments due to winds, waves and earthquakes, which produce cyclic axial loads in piles, and prediction of axial soil reaction to a pile becomes an important design consideration.
The beam-on-Winkler foundation method has been commonly used to obtain the axial response of piles. The beam-on-Winkler foundation method approximates the soil reaction, which is continuous with depth, by a series of isolated soil springs, and the method neglects the interaction between such soil springs. Due to this simplification the method is efficient. The method, however, has been shown to yield reliable pile responses when the method is used with appropriate soil springs. Therefore, the reliability of this method is controlled by our ability of predicting realistic soil springs to be used with the method.
Such discretized load-settlement relations along the pile shaft and at the pile tip were first proposed by Seed and Reese (1957) and Coyle and Reese (1966) and these relations have been commonly referred to t-z and Q-z responses. The t-z response represents the load-settlement relation along the pile shaft and the Q-z relation is for the pile-tip load and tip settlement. The t-z and Q-z relations for design purposes have been based mainly on field pile-load test data.
Various analytic techniques have also been used to predict t-z and Q-z relations. The Mindlin's solution (Mindlin, 1936), which represents the displacement due to a point load within an elastic half space, has been integrated over the pile surface to derive t-z and Q-z relations by various researchers (e.g. Poulos and Davis, 1978). The concentric ring approach has also been used for this purpose (Kraft, Ray and Kagawa, 1981; Armaleh and Desai, 1987).
The t-z and Q-z relations, however, are not unique for a given soil condition, but they are strongly influenced by soil and pile parameters. Most existing methods fail to include the impact of soil-pile parameters on t-z and Q-z relations. The state-of-the-art on this subject indicates that the t-z and Q-z relations, which can be easily combined with existing pile settlement analyses, are not available for various soil-pile parameters of our interest.
The Use of Three-Component Downhole Geophones Results in Improved Salt Proximity Surveys
Authors: Wilson P.H. 
Published: October 2008

ABSTRACT
Recent advances in VSP tools and VSP analysis techniques can be used to reduce the uncertainities associated with Salt Proximity Surveys. Using these advances, the direction selsmtc energy is traveling at the geophone is measured and used to determine a slngle salt exit point instead of the usual aplanatic curve (the locus of all posslble salt exit points).

INTRODUCTION
The Salt Proximity technique is one of the oldest geophysical techniques known. The Salt Proximity survey is designed to answer an Important questlon critical to successful exploration and production In the vicinity of salt domes, After a well is drilled in the vicinity of a salt dome, whether the well is successful or not, the next question that is asked is how far from the salt mass did the well penetrate. A Salt Proximity can be conducted to try to answer thls questlon. This paper will demonstrate some improvements that have been made to thls old technlque. These improvements were realized by applylng recently developed VSP tools and analysis techniques to Salt Proximity surveys. In particular the current practlce of using three component downhole geophones and arrival direction measurements from hodogram analysis allows some of the uncertalntles of Salt Proximity surveys to be resolved. I will then show how these techniques were used on a real salt dome to find a salt protrusion.

BACKGROUND
The Salt Proximity survey is based on tihe fact that salt has a significantly higher sonic veloclty than sediments. The salt proximity survey is conducted In the following manner. A set seismic source is placed on the surface above the top of the Salt mass and a geophone ts placed in the well. The first arrival time of the seismic energy is recorded on the geophone. Since the locat ion of the source and the geophone are known, the distance between them is known. In most places the seismic veloct ty of salt is constant and known. If only salt existed between the source and the geophone the first arrival time would be (source to geophone distance)/(salt velocity). Any first arrival time greaterthan this is due to the existence of sediment of lower velocity between the source and the geophone. Furthermore the amount of excess first arrival tlme would be proportional to the amount of sediment bet ween the source and receiver if the energy traveled in a straight line from the source to the receiver. The amount of sediment could be determined if the velocity of the sediment were known or could be guessed. The downhole geophone has undergone a considerable development in the last several years. First it was determlned that the recorded signal could be improved if the geophone tool was clamped to the well bore. Then It was determined that better signals were recorded if the welght of the geophone tool was reduced, This led to the development of tools with high clamptng force to welght ratios.
A New Laser Tool and Seabed Pressure Gauges for Measuring Platform Elevations With Respect to the Mean Sea Level
Authors: Mes M.J. 
Published: October 2008

ABSTRACT
Phillips Petroleum Company and Co-venturers pioneered the use of pressure gauges and a new Laser tool to measure the elevation of selected Ekofisk Area platform decks above the Mean Sea Level (M.S.L.). Periodic measurements of this type became necessary after subsidence was noticed in the Ekofisk field in late 1984.
This paper describes the successful development and application of a laser based tool to measure the absolute platform elevations with respect to the Mean Sea Level, which were established to an uncertainty less than 0.06 meters with respect to the Mean Sea Level. The laser data were also used to make near-seabed pressure gauge data compatible with laser measurements for continuous monitoring of the platform elevation with respect to the Mean Sea Level.
The interpreted seabed pressure gauges and laser measurements make it possible to determine the airgap of a platform, that is the distance between the crest of the 100-year design wave and the lowest point of the cellar deck beam. Accurate historical knowledge of the airgap of a subsiding platform from several surveys enables us to predict the timing of necessary structural remedial work related to subsidence.

INTRODUCTION

BACKGROUND
Phillips Petroleum Company Norway is the operator for the Ekofisk Field, located roughly in the center of the North Sea. Figure 1 shows a geographical location map. Several platforms, located near the center of this field, are connected by bridges. This group of platforms is referred to as the Complex. All platforms in the complex were jacked up because of the large subsidence in this Central Ekofisk Field area. Currently, the subsidence at the complex is approaching 5 meters. The Ekofisk Field was discovered in 1969 and has produced oil and gas since 1971.
In November 1984 it was discovered that subsidence takes place in the central Ekofisk field. Several measurement techniques were used to obtain information on the total amount of subsidence and the subsidence rate. In order to plan subsidence modifications, the distance from the lowest point of the cellar deck beam to the 100-year wave crest, defined as the "airgap", was needed. Historically we had used "brace gap measurements" to derive the airgap, but we had established that these are not very accurate. A brace gap is defined as the distance from a specified point on the spider deck to the perceived average water level by visual readings on a vertical steel tape. This definition is in agreement with the historical meaning of the word. Finally, a measuring system based on pressure gauges was installed in 1987. (Figure 2). It was thought that it could also be used to calculate the airgap for future reference.
The current paper explains how this was done by combining pressure gauge data with a newly developed laser tool for the Fall 1989 survey.
Methods of Prediction of Tubing Life for Gas Condensate Wells Containing CO
Authors: Adams C.D. , Garber J.D. , Fang C.S. , Perkins R. , Reinhardt J.R. 
Published: October 2008

ABSTRACI'
A review has been made of various corrosion models available for the prediction of the life of carbon steel tubulars in carbon dioxide containing environments. These models range from relatively primitive empirical relationships to more sophisticated methods that involve the liquid film inside a production string and the solubility of iron carbonate. One of the models shows the prospect of being able to predict the onset of erosion corrosion. Particular emphasis has been placed on the corrosion models that are part of the USL Corrosion Computer Model.

INTRODUCTION
The ability to predict the life .expectancy of a carbon steel tubular in a gas condensate well containing carbon dioxide is a goal of corrosion engineers in the oil and gas production industry. Gas condensate wells are much more complex than typical oil wells since in addition to temperature-pressure changes with depth, there are phase equilibrium changes and flow dynamic conditions that must be considered. The final step of converting this information into a corrosion rate and then a tubing life is perhaps the most difficult task.
Two excellent NACE publications (1,2) have clearly illustrated the complexity of carbon dioxide corrosion. A number of investigators have attempted to predict corrosion rate in wells containing carbon dioxide. - Perhaps the best known work is that of DeWaard and Milliams (3), which relates corrosion rate to partial pressure of CO2 and temperature. Others like Crolet and Bonis (4) have developed proprietary models to predict tubing life from field data. The COPRA correlation developed by Gatzke and Hausler (5) is an empirical approach which uses iron counts and production rates of fluids to establish corrosion rates.
The Corrosion Research Center at the University of Southwestern Louisiana has developed a computer program which successfully models gas condensate wells using first principles (6,7). Phase III of the program consists of 7 programs listed as Models A-G. The program was released to sponsoring companies during the spring of 1988. This program can be divided into two groups of models that physically describe a gas condensate well: Models A, C, E, and G; and those that predict tubing life: Models B, D, and F. Although Models B and D can be run without any dependency on other models, Model F must have information from other models before it can be run.
A brief description of each of the physical models follows:Model A - This is the temperature-pressure profile model which allows one to calculate the temperature and pressure at any point in the production string given the bottom hole temperature and pressure. The calculations are performed for a dry gas and a gas condensate well.Model B - This phase B equilibrium model uses the Peng-Robinson equation of state to calculate the phases that exist at any point in the production tubing. There is a possibility of a single phase, of two-phases, or of three-phases existing in the tubing.
Snorre Subsea Production System
Authors: Childers T.W. , Øvergaard I. , Helle E. 
Published: October 2008

ABSTRACT
Saga Petroleum will make extensive use of subsea systems to develop the Snorre Field. Of the planned 46 wells needed for the field's first phase development, 10 will be subsea wells. Another 47 subsea wells may be added during the second phase development, bringing the total to possibly 57 subsea wells.
The Snorre Subsea Production System was previously described in OTC paper 62021. This follow-up paper expands the discussion of the system with emphasis on some of the more innovative aspects of the design. Specific issues addressed are: guideline-less drilling and completion system, the manifold system, control system, TFL well-servicing, and the remotely operated maintenance vehicle which will be used to maintain the manifold and control system components.

DESCRIPTION
The Snorre Subsea template system is shown in Fig. 1, which identifies the various sub-systems that comprise the template system. The 10 + 10 template will develop 20 wells, but only 10 at a given time. As a well is depleted it can be abandoned and replaced with another drilled through the same template.
The template system is 48 metres long, 32 metres wide, and (including the 3 metre skirts) 19 metres tall. As installed, with the manifold sub-system (but not the well bay equipment, which will be installed as the wells are drilled) it weighs approximately 2500 tonnes in air. It will be installed by a heavy lift crane vessel in 335 metres water depth, 6 kilometres NE of the Snorre TLP. The template structure is a truss structure made primarily of large diameter tubulars. It features upright sections that provide separating walls between the well slots. These walls, which give the template the appearance of an English "toast rack," serve to protect the adjacent equipment during drilling and installation operations in the adjoining well slot and also are used for guidance of equipment into the well slot.

DRILLING AND COMPLETION
Immediately after the template is installed it will be leveled by pressuring or applying suction to the skirted mud-mat compartments. Thirty-inch conductions will then be installed in the four corner well slots to stabilize the template. The remaining 6 conductors will then be drilled, cemented, and locked to the template wellguides to complete the foundation. Conventional drilling and completion equipment and casing programs will be used for the Snorre subsea wells, with the exception that guideline-less techniques will be used to install equipment. As previously mentioned, the "toast-racks" play an important role in the guideline-less system. Figure 2 shows a cut-away view of a well slot. One of the two "toast-rack" members is illustrated with its "bumper," the "well guards," and the two drilling guides, that are in each well slot. The bumper, including the corresponding one on the other "toast rack" that has been cut away, interact with bumper plates mounted on the BOP's alignment structure and the tree's alignment structure to position the equipment for installation on the wellhead.
The Tension Buoyant Tower: A Design for Deep Water
Authors: Halkyard J.E. , Paulling J.R. , Davies R.L. , Glanville R.S. 
Published: October 2008

ABSTRACT
The Tension Buoyant Tower (TBT) consists of a cylindrical spar type buoyancy module moored to the sea bottom by a group of tendons arranged in a pattern close to the centerline of the buoyancy module. The buoyancy module consists of buoyant hard tanks extending to a depth of 250 feet or more depending on the specific requirements of the design. An upper stem extends below this point to a depth of 500 feet or more. Seven tendons pass through a centerwell in the buoyancy module and extend to the seafloor, passing through a lower stem before template. Local tendon bending stresses are limited by tapered tendon sleeves at the entrance points to the upper and lower stems. The tendons and sleeves are allowed to pivot at these points, eliminating the need for elastomeric flex joints. Coupled analysis of the design was performed using the finite element program COPIPE. The key parameters in the design include: base tension, location of platform CG and CB, sleeve design and location of tendon support points within the stems. The results of analysis showing the sensitivity of the design to these and other parameters will be discussed. Application of the TBT to Gulf of Mexico applications ranging from 1,000 feet to 10,000 feet will be reviewed.

INTRODUCTION
Deep water Gulf of Mexico development will undoubtedly involve the use of innovative structures for drilling and production. We have already seen the first deep water tension leg well platform at Jolliet, the World's deepest floating drilling and production platform at Green Canyon Block 29 and in 1992 will see another deep water drilling and production platform at Auger. All of these were preceded by the guyed drilling and production tower at Lena. As water depth increases it becomes ever more difficult to provide structures which allow surface drilling and completion.
The TBT allows drilling from the structure coupled with traditional surface trees.
The TBT (Figure 1), is a compliant offshore structure used for drilling and producing oil and gas in water depths ranging from 1,000 feet to 10,000 feet. Low cost and simplicity are its principal features. The structure relies on buoyancy to keep it upright and on bundled vertical tendons to maintain its position. The lower ends of the tendons are fixed to a base which is pile fastened to the seafloor. Although the TBT can be designed to support any deck load, it is well suited to supporting drilling and production facilities in the range of 5,000 to 25,OOO tons.
The drilling and production equipment is similar to that used on conventional fixed or compliant platforms. Conductors are supported by sleeves and/or spacers from the well deck to the mudline. They are pretensioned to level required to prevent buckling under the extreme pitch motions of the TBT, approximately 6 degrees. Wells can be drilled from, and completed on the deck of the TBT as is done on fixed platforms.