bluuebunny/crossref_metadata_2025 huggingface dataset:
Prevention of Upheaval Buckling of Hot Submarine Pipelines by Means of Intermittent Rock Dumping
Authors: Ellinas C.P. , Supple W.J. , Vastenholt H.
Published: October 2008

The extraction of oil and gas from marginal reservoirs has become feasible through the development of sub sea completions. As a consequence of the adoption of this technology, untreated oil and gas often at high temperatures is being transported from such completions to surface facilities by pipelines, which are therefore exposed to the effects of thermal expansion. Frictional restraint to such expansion causes built-up of high compressive forces which can in turn cause the pipeline to buckle. This paper reports on how such a potential problem was assessed and resolved in 1985.

INTRODUCTION

In 1985 a dual TFL 4-inch flow line system was installed in Shell Esso's Central Cormorant field in the North Sea between satellite well P5 and the Underwater Manifold Centre (UMC). The length of the flow line system is about 3km and the operating temperature is in the range 75 °C-85°C. As a result, designing these Flow lines, whilst ensuring their safe operation, meant making provisions for avoiding possible buckling due to restrained thermal expansion.

Initial analysis of the flow lines indicated that they would not remain stable in their shallow open trench, unless they were either buried deep or covered with a layer of rock. However, these options were considered unattractive. The method eventually chosen was based on allowing the flow lines to snake in a controlled manner, by securing them to the seabed with intermittent piles of rock dumped at predetermined intervals along the pipeline. The Central Cormorant P5 flow lines were taken into operation successfully and subsequent inspection of the lines has vindicated this innovative solution.

Recent developments in the North Sea have led to an initiative by several oil companies to embark on a joint research programmed on upheaval buckling [1,2]. In this context, it is considered timely that the methodology for avoiding upheaval buckling due to thermal expansion, as adopted in 1985 for the Central Cormorant P5 lines, be presented as it may be suitable for other small diameter pipeline projects.

BACKGROUND TO THE PROBLEM

For the extraction of oil from the central area of Shell Esso's Cormorant field the oil is passed through the UMC and transported by flow lines to the Cormorant 'A' platform. The UMC project is well documented in various publications, for example Reference [3]. At Cormorant 'A' the oil is treated to make it suitable for export to shore by pipelines.

If the crude were to be allowed to cool to ambient temperature, whilst being transported to Cormorant 'A' platform, wax would be deposited at a temperature below 32 °C and formation of hydrates would occur at a temperature below 15 °C. To avoid blockage of the flow lines, a thermal insulation had to be applied to these lines over their entire length to maintain temperature high and thus ensure that the above phenomena would not occur.
Design of Submarine Pipelines Against Upheaval Buckling
Authors: Palmer A.C. , Ellinas C.P. , Richards D.M. , Guijt J.
Published: October 2008

This paper describes part of a comprehensive joint-industry project on upheaval buckling. It develops a semi empirical simplified design method and detailed design methods based on a new numerical analysis, and illustrates their application by examples. It assesses alternative design strategies, and the implications of strain-based design.

INTRODUCTION

When a pipeline is operated at a temperature and pressure higher than ambient, it will try to expand. If the line is not free to expand, the pipe will develop an axial compressive force. I£ the force exerted by the pipe on the soil exceeds the vertical restraint against uplift movement created by the pipe's submerged weight, its bending stiffness, and the resistance of the soil cover, the pipe will tend to move upward, and considerable vertical displacements may occur. The pipeline response might then be unacceptable because of excessive vertical displacement or excessive plastic yield deformation. Upheaval buckling is hence a failure mode that has to be taken into account in the design of trenched and buried pipelines.

The possibility of upheaval buckling is of increasing concern to the operators of flow lines in the North Sea and elsewhere. Their concern has been heightened by upheaval buckling incidents in the Danish and Norwegian sectors, and by the cost of protective measures such as rock dumping. Shell International Petroleum Maatschappij (SIPM) initiated a comprehensive upheaval buckling research program in 1987. In its final form, the research program included six phases:review of available models;comparative analysis;cover response, testing and modeling;numerical upheaval buckling model;analysis of alternative concepts;development of an upheaval buckling guideline. The present paper is one of a series describing the results of the programmer. It concentrates on phases 5 and 6, which were subcontracted by SIPM to a joint venture of three UK engineering companies r Andrew Palmer and Associates r Advanced Mechanics and Engineering, and Lloyds Register.

The paper is primarily concerned with the design aspects of upward buckling of buried pipelines. Unburied pipelines can buckle in a related but different mode, in which they snake sideways across the seabed. This mode too is important in practice and can play a major part in relieving the effects of axial force, but it is outside the scope of the present paper.

The paper first briefly describes the phenomenon, and puts forward a simplified method for preliminary design. It goes on to describe a conceptual design method based on the application of the UPBUCK program, and applies the methods to a design example. The paper then considers alternative strategies to resolve upheaval problems, and examines in more detail one of these strategies, a reduction in wall thickness made possible by the replacement of stress criteria on longitudinal stress with strain-based design criteria.
Jolliet: The Project
Authors: Koon J.R. , Langewis C.
Published: October 2008

This paper overviews the management, design, fabrication and installation of the Jolliet Project and briefly summarizes the companion Marquette Project. This work includes the Tension leg Well Platform (TLWP), the central Production Platform (CPP), 54 miles of pipeline and the GC52A drilling platform.

The TLWP is the first-ever tension leg well platform and is the world's deepest offshore production platform. The project took four years to design, fabricate and install. This paper discusses the field history, concept development, the scope of the project, and its management, design and construction.

INTRODUCTION

The Jolliet Field in the Gulf of Mexico Green canyon GC Block 184 was discovered in May of 1981 with a well drilled in 1,500 feet of water. A further six wells, over a four-and-a-half-year period, were required before development was approved in early 1986. Evolution of the development concept also occurred during this time period. The oil price crash of 1986 delayed construction but not detailed engineering of the TLWP.

Once construction work was approved in 1987, the project went into high gear, completing the drilling of twenty wells, installation of a 1,760 feet world record water depth tension leg platform, over fifty miles of pipelines, a large central production facility in 616 feet of water and commencement of well completions and oil production. This was accomplished in less than three years and nine percent below the original budget.

The projects are named after Louis Jolliet and Jacques Marquette, the 17th century French Canadian explorers of the Mississippi River.

Their spirit of exploration of the unknown is shared by the men and women who worked on these projects.

This paper overviews the history and accomplishments of the project and sets the stage for the nine other papers which comprise the Jolliet Project Special sessions.

FIEID HISTORY

Green canyon Block 184 is in the Flexure Trend on the continental slope in the Gulf of Mexico, about one hundred miles offshore central Louisiana (Figure 1). The lease was acquired by conoco, Getty and cities service oil companies as equal partners in November of 1980 for a bid of $7.aMM. It was a five-year Net Profits Share lease (NPSL) with a 100 percent capital recovery factor and a 50 percent net profit share factor.

In simplified terms, this means that no conventional royalty is paid on production from the lease. Instead, 50 percent of the net revenue of the lease is paid to the MMS after 200 percent of money invested in the lease, prior to production, has been recovered by the lessees.
Added Mass and Damping of a TLP Column Model
Authors: Chakrabarti S.K. , Hanna S.Y.
Published: October 2008

The Tension Leg Platform (TLP) typically has a very high natural frequency in vertical (heave) motion. While the wave energy is quite small near this natural period of 2 to 4 seconds, the nonlinear forces can introduce excitation at the natural frequency, giving rise to large tendon loads. This phenomenon is commonly known as " springing". The damping values of the TLP leg in the vertical direction are very important in the computation of this load. Little is known about these damping characteristics.

In order to investigate the hydrodynamic damping of a TLP, model testing of a vertical column of a typica1 TLP was performed. This test used a vertically moored cylinder to represent a TLP column at a scale of about 1:20. The mooring 1ines which restrained the cylinder were a pair of linear springs attached to the top and bottom ends of the TLP leg. The cylinder was oscillated in still water and in waves to record the decaying oscillations, and thus provided data to calculate the damping values. The cylinder was also mechanically oscillated with known sinusoidal motion, and the resulting loads were recorded.

The hydrodynamic added mass and damping coefficients of the vertical caisson covering a wide range of natural periods and wave frequencies have been presented. Results of this investigation can be readily used and applied in the design of TLP's. The use of the damping values found in this study will reduce predict ions of TLP mot i on and tendon loads. For deep water TLP applications, the associated cost savings can be significant.

INTRODUCTION

Many offshore structures that are floating and moored to the bottom of the ocean respond to waves at two different frequencies. One of these frequencies is the wave frequency while the other is the frequency corresponding to the natural frequency of the system (if it is distinct from the wave frequency). For a ship-shaped floating body, the natural frequency in surge is low so that the second peak appears at the low end of the power spectrum plot. On the other hand, for a vertically moored TLP, this frequency in heave falls at the high end of the spectrum. In both these cases, the exciting force is of second-order and, thus, proportional to the square of the wave amplitude (in regular waves). The response of the floating vessel is increased near the natural frequency due to the dynamic amplification. The resonant response of the vessel is limited by the amount of damping present in the system, The damping generally appears from two natural sources. One of them comes from the springs themselves, called
An Analysis of the Dimensions of Embedded Defects in the Welds of an Offshore Structure
Authors: Kountouris I.S. , Baker M.J.
Published: October 2008

This is one of a series of papers describing an analysis of the occurrence, size and type of defects in the welds of the lower hull of the Hutton Tension Leg platform found during a detailed survey of the structure in the late stages of fabrication. This paper gives the results of an analysis of the dimensions of embedded defects detected and sized by ultrasonic testing, and involving the examination of approximately 27 km of weld by the method. Analysis has been undertaken of characteristics such as defect width, defect length and aspect ratio. Sufficient data were available to investigate the influence of parameters such as the type of welded joint, welding process, welding procedure and defect type on the defect dimensions. Results are given in terms of the statistical distributions of the sizes of embedded defects for different types of welded joint and types of defect, and are based on a sample of approximately 8300 defects.

INTRODUCTION

This paper describes the conclusions reached during a detailed analysis of the dimensions of embedded defects in the welds of the lower hull of the Conoco Hutton Tension Leg Platform (TLP).

The data that have been analysed are part of a large data bank compiled from the results of the non-destructive examination (NDE) of about 27 km of weld by ultrasonic testing (UT) and about 76 km of weld by magnetic particleinspection (MPI) - a total of 121,270 UT and MPI examinations. These data have provided considerable scope for analysis and a general overview of some of the results has already been published by Baker et al.1 A subsequent more detailed analysis of the frequency of occurrence of defects and the occurrence of multiple defects has been given by Kountouris and Baker.2

This paper is concerned with the distribution of the size of embedded defects and with the relative frequenty of occurrence of defects of different types. Information on the sizes of surface-breaking defects has been reported elsewhere.3 In addition, a number of detailed report a have been prepared which discuss various aspects of the analyses undertaken.4–6

Knowledge of the occurrence rate and size distributions of defects in completed structures and knowledge of the factors which influence them are useful in the planning of NDE procedures and also in the safety assessment of structures which could fail by fatigue and fracture, see e.g. Ref. 7. It must be stressed, however, that because the structural form of the Hutton TLP is radically different from that of typical jacket structures, having details more akin to those found in ships' hulls, care should be taken in extrapolating the conclusions from the TLP to other forms of offshore construction.

BRIEF DESCRIPTION OF THE STRUCTURE AND NDE HISTORY

The Hutton TLP is well known as the first tension leg structure and was installed in the North Sea in 1984, with oil production starting later than year.
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

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

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

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

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

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.
Safety Survey Using Piper Alpha Disaster Evidence
Authors: Hall J.N.
Published: October 2008

The Piper Alpha Public Inquiry heard 13 months of evidence. In that time much about what happened on the day of the disaster became known. It also became clear that inadequacies existed in accepted industry safety practice. Lord Cullen, the Judge in charge of the Inquiry, reported a considerable part of this evidence in his recent report and recommendations. Conoco wanted to ensure it learned all it could from the Inquiry. It wanted to learn not only from the report, but anything else it could learn directly from the evidence itself. It wanted to check its own safety systems against the evidence. Finally, to enhance safety awareness generally within the company, it wanted to make known to its employees as much as possible about the evidence and the safety lessons it provided.

INTRODUCTION

Immediately following the piper disaster, Conoco - like most companies operating in the UK - thoroughly examined all aspects of its safety policy and practices. TO do this, a number of teams were formed incorporating personnel from production, safety and engineering. Each team reviewed an area for possible safety improvements to its North Sea facilities. These are some of their recommendations:Locate pipeline emergency shut down valves in a safe position. Generally, this meant positioning the valve in the cellar deck close to the top of the riser. Then appropriately protecting the valve from all identifiable sources of explosion and fire.Relocate Viking 'A' and 'B' accommodation to a dedicated support structure. Conoco has two separate multi-platform complexes close together. Quarters on each are on platforms with import pipeline risers. As the water is shallow (100ft) it is realistic to provide a dedicated accommodation support structure. Rather than built two such dedicated units, a single unit at one complex is to be built, with the second complex then unmanned and remotely operated from the first.Mark out escape ways to be visible in dark smoky conditions. Originally the escape routes were full yellow painted roadways, but because these proved slippery in wet conditions black anti-slip tiles were fitted. Yellow photoluminescent discs spaced at regular intervals have now been applied along these routes.Supply grab bags in all bedrooms. All crew members now have by their beds a bright yellow holdall which contains all their survival equipment: survival suit, life jacket, smoke hood, and leather gloves. So in an emergency people can quickly grab their bags as they hurry to their muster station, with less chance of any essential item being forgotten or difficult to find - particularly in dark or smoky conditions.Provide torches in all bedrooms.Mark exits from accommodation. Exit doors have always been illuminated. Now, in addition, all internal walls (at floor level), door frames and door handles are outlined with photoluminescent tape to improve their visibility even in thick smoke.Fit guards on subsea fire pump suction caissons. Prior to fitting these cages it was common industry practice to isolate the fire when divers were working close to the pump suction.
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

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.
Structural Requirements for the Effective Transfer of Environmental Loadings in a Subsea Wellhead System
Authors: Milberger L.J. , Yu A. , Hosie S. , Hines F.
Published: October 2008

This paper reviews the evolution of design requirements for subsea wellhead housings used in offshore drilling. Structural integrity is paramount in order to resist environmental loadings. A new wellhead design incorporating a pair of axially spaced tapered sockets is presented. Results of detailed computerized analysis along with test data on a full-scale test article are presented. A review of field operations for the new design is presented along with the design of a tool which can be used to seat the sockets, thus making the system useful for extreme fatigue-rated drilling.

INTRODUCTION

Early subsea wellhead system designs used a single landing or support shoulder between the 18-3/4" subsea wellhead (HP housing) and the 30" conductor housing (LP housing). This type of configuration was found to operate well and provided years of successful operation until two field failures occurred[8][1]. Both involved drilling in high current conditions. Hopper[1] reports that an exploration well being drilled in the North Sea west of Shetland had to be abandoned 29 days after running the HP housing due to the fatigue failure of the weld between the casing extension and the wellhead body.

These unexpected failures of subsea wellhead housings during drilling operations prompted an in-depth study into the behavior of a subsea wellhead system when it is subjected to external bending loads. Most of these studies were completed using simple two-dimensional finite element analysis and a maximum bending moment of about 1 million foot pounds, as discussed in references [3], [4], [5], [6], and [7], although reference [2] clearly addresses bending loads above 2 million ft.-lb. The results of all these studies showed that the magnitude of the bending stresses developed in the casing extension below the high pressure wellhead housing is greatly affected by several factors:Type of interface between high and low pressure housings, i.e., single or double socket type.The radial clearances which exist at the socket.The effective cement level in the annulus between the 30" conductor and the 20" casing extension.The size of the wellhead extension.The amount of applied load.

Further, these studies showed that to ensure a subsea wellhead system has sufficient structural integrity to endure the static and fatigue bending loads which may be encountered during drilling and production operations, a wellhead system should preferably employ a dual socket interface with the radial clearance at these sockets suitably adjusted to the vertical distance between the sockets.

The magnitude of environmental loadings continued to increase with the introduction of Tension Leg Platforms (TLP), because drilling or production risers on these vessels remain connected to the subsea wellhead system in all conditions. This factor automatically results in a considerable increase in the static and fatigue loading which the wellhead system will experience.
A 78° Extended Reach Well in the Gulf of Mexico, Eugene Island 326 No. A-6
Authors: Kimball C.F. , Colwell C.N. , Knell J.W.
Published: October 2008

This paper describes the successful drilling & completion of Forest oil Corporation's OCS-G-5518 No. A-6, Eugene Island Block 326. The subject well was drilled as a 79 deg high angle extended reach well (ERW) from an existing production platform in the adjacent Eugene Island Block 325. The purpose was to establish production from a shallow sand located at a depth of 2300 'TVD(701M) at a reservoir take point located 7000' (2134M) from the existing platform. The paper focuses on the engineering aspect of the well plan and the operational problems that were encountered.

The final results indicate that a shallow extended reach well with an MD/TVD ratio of 3.1:1 can be successfully drilled and completed in the Gulf of Mexico. The techniques used and the lessons learned can be applied to any area with modifications for that particular drilling area. Existing platforms can be used to cut cost and to protect adjacent leases as "Held By Production". New platform placement can take into consideration the drilling of extended reach wells.

INTRODUCTION

Forest oil Corporation (FOC) drilled a discovery well, OCS-G-5517 No.3, in Eugene Island Blk 325 in November of 1987. The well was a straight hole drilled to 6100'MD/TVD(1859 M). A six well drilling template was then placed over the No. 3 well and several additional wells were drilled using a jackup drilling rig in 255'(78 M) of water.

Another discovery well, OCS-G5518 No.2, was drilled in Eugene Island Blk 326 in March of 1988 to 4939'MD/TVD(1505 M). This well found a productive sand at 2300'(701M). A platform was then set over the drilling template in E.I. Blk 325 and tieback and completion operations were begun. Figure 1 shows the location of Eugene Island Blocks 325 and 326.

It became necessary to establish production from E.L Blk 326 and "HOLD IT BY PRODUCTION" in an economical manner. Several options were considered.Set a minimum offshore structure (MOSS) over the existing discovery well in Block 326, install test facilities only, and flow to the existing platform in Block 325 for processing.Perform a subsea completion flowing to the existing platform in Block 325 for processing.Drill and complete an ERW from the existing platform in Block 325.

The cost analysis showed that options 2. and 3. would cost approximately the same and that option 1. would cost twice as much as the other two. Because of the cost and because of the mechanical problems often associated with option 2., option 3. was chosen. The basic directional plan was as follows.Build at a rate of 6 deg/100' from the surface to a maximum angle of 77 deg 19 min at 1389'MD(423M)/1000'TVD(305M).Hold the angle of 77 deg 19' to a total depth of 7169'MD (2185M)/2300'TVD (701M).

This plan resulted in an MD/TVD ratio of 3:1:1. Figure 2 shows the spider plot of the wells drilled from the Eugene Island Block 325 production platform.
Pigging of Subsea Pipelines
Authors: Schaefer E.F.
Published: October 2008

AN ART?....A SCIENCE??

As offshore developments move into greater water depths the problems of slugging, associated with condensate drop out and two-phase flow in gas pipelines becomes particularly acute at the pipeline riser. These vertical sections of pipe, some of which are over 350 m high, present some interesting problems in relation to slug formation and removal as the pressure varies due to the head of liquid which may build-up during some operational phases.

Factors Affecting Two-Phase Flow

Gas-Liquid Ratio

The basic behavior depends on whether or not both the liquid and gas phases are present as a continuous phase.

In bubble flow, one has a series of bubbles of gas in the liquid, and gas N not in a continuous phase.

At the other end of the scale--spray or mist flow, small amounts of liquid are suspended in the gas. Now, liquid is now the discontinuous phase and the gas is the continuous phase.

In systems where both the gas and liquid are continuous, the character of the flow is more difficult and de ends on such variables as phase densities, viscosities, and velocities of each phase.

Volume/Flow

Under certain conditions, constant flow can be maintained without the use of spheres, if the flow velocity is sufficient to keep the liquid moving. However, under most conditions, periodic pigging must be maintained to provide the maximum efficiency.

Operating Pressure/Design Pressure

As liquid columns increase in size in each valley, the total pipeline pressure differential increases to the point where up-stream pressure may be increased in excess of the MAOP (maximum allowable operating pressure). The importance of periodic pigging is now obvious.

Allowable Pressure Drop

Liquids that sag in valleys cause pressure differentials as the gas pushes the liquid level to the point where the gas has to bubble through the liquid column in order to maintain flow.

Velocity of the Gas-Liquid

Due to the interaction between discrete phases, the gas moves more rapidly than liquid and can cause problems down-stream as the column of fast-moving liquid comes to the slug catcher.

During the life of a pipeline, depending on the transported fluid and its service conditions, the pipe wall will deteriorate, possibly through corrosion or as a result of scale or other solid deposits adhering to it.

This will cause the deterioration in the economics of the pipeline operation due to increased pressure drop in one of two ways, Firstly, the deposits may effectively reduce the pipeline diameter and thus its throughput capacity and secondly, the roughness of the pipe wall may be increased with its attendant adverse effect on pressure drop.

For example, the presence of wax in crude oil can lead to the precipitation of wax deposits on the pipeline wall. This wax deposition is time dependant but a thin layer can build up quickly to produce, on larger throughputs, significant reductions in line capacity.

Why Pig?

There are basically four reasons for pigging a pipeline.