bluuebunny/crossref_metadata_2025 huggingface dataset:
The Delta Tower: A Light, Compliant Tower for the Gulf of Mexico
Authors: des Deserts L. , Cortez A.J.
Published: October 2008

The concept which is described in the paper is applicable to fields located in the Gulf of Mexico in water depths ranging from 1 000 to 1 750 feet. The concept is a compliant tower which permits the use of conventional equipment for drilling and production and which is immediately applicable without any need for specific developments. Because of the low quantities of materials involved, and since conventional equipment can be used, the concept is particularly well adapted for marginal fields, as well as for larger ones. Material quantities are given for different water depths and deck loads, as well as dynamic behavior and the outline of the installation procedure.

INTRODUCTION

The Delta Tower is a concept which was originally developed through a joint industry study supported by 10 American oil companies, for hydrocarbon production in 2 500 feet of water depth. See reference 1. It is a comp1iant tower supported on a fixed base and having its stability brought by some axial tubes located at its periphery. The connection between the tower and the base is ach leveled by some tubu1ar members allowing the heeling of the tower and able to transfer the overall shear force to the foundation. The paper will present the latest works performed on this concept, which are related to water depth ranging between 1 000 and 1 750 feet.

MAIN PRINCIPLE

The Delta Tower is a concept which features a compliant structure, called lithe Tower", set on top of a fixed one, called lithe Base". The compliancy of the upper part is brought by three different means : the axial tubes, the buoyancy tank and the shear device.

The axial tubes, located at the periphery of the tower, are rigidly connected to the tower and to the base at their top and bottom extremities respectively. In addition, they are simply guided along the tower and the base to prevent any possib1e buck1ing. These tubes act as vertical springs and, because of their eccentricity with regards to the axis of the tower, they provide the necessary righting moment in the tower when it heels under wave action. They also permit the transfer of all vertical loading between the tower and the base.

The buoyancy tank, located below the water line at a low enough level to minimize the wave loads, produces also a part of the righting moment and permits to reduce the apparent weight of the structure which is supported by the axial tubes.

The shear device, located at the bottom of the tower permits the transfer of all shear forces and torsion moment between the tower and the base. This shear device may be composed of a set of shear pins - shear guides or by a set of shear members. The high flexibility of these shear members combined to their axial resistance creates d pseudo-articulation between the tower and the base.
Application of Model Pile Tests to Axial Pile Design
Authors: Bogard J.D. , Matlock H.
Published: October 2008

Experiments conducted with instrumented model pile segment probes at Harvey and Empire, Louisiana are summarized and the observed behavior interpreted. Correlations are developed for the time rate of strength gain and interim recommendations are given for construction of t-z curves (soil resistance versus axial pile displacement) for use in design. The methods are compared with existing pile test results.

INTRODUCTION

A comprehensive program of studies of the behavior of axially loaded piles in normally consolidated clay was performed between 1982 and 1986. The studies included a large number of experiments with instrumented pile segment models which were deployed below the bottoms of boreholes. Some were near the sites of large-diameter pile load tests. Continuously recorded measurements included pore pressure and total lateral pressure plus soil shear resistance as a function of axial displacement, under a variety of static and cyclic loadings.

The results of selected experiments done in Louisiana at Harvey and Empire have been given in two companion papers (Refs 1 and 2). In this paper, the complete sets of results will be used to establish proposed interim design procedures for axially loaded piles in similar clays. The procedures will then be applied to two sites at which axial pile load tests have been performed in normally consolidated clays.

SUMMARY OF OBSERVED SOILPROBE BEHAVIOR

A fairly clear concept of the mechanisms of clay soil behavior in interaction with axially loaded piles has been obtained in part from the Harvey and Empire test results. The principal features are summarized here as a basis for the development of correlations and design procedures. In general, when a pile is pushed or driven into the soil, the soil is displaced outward by an amount which is, in terms of analysis, referred to as cavity expansion. The soil is also remolded by the flow around the point and by shear deformations along the length of the pile.

Excess lateral pressures are created by the cavity expansion, primarily in the pore water and therefore in the total pressure. Because of the rapid reduction of shear stress with radial distance from the pile, the significant lateral and shear stresses are confined to a soil band very close to the pile wall.

With time during and after pile installation, the pore water pressure dissipates by a process of radial consolidation and a part of the lateral pressure is transferred to lateral effective stress. Since the process involves the outward migration of pore water there is a slight movement of the soil skeleton inward toward the pile. This results in a reduction of total pressure during consolidation.

A closed-end or plugged pile forces more soil to move laterally and thereby creates somewhat greater initial lateral pressures than an open-end or thin-wall pile. The band of remolded and heavily stressed soil around the thin-wall pile is much thinner, resulting in more rapid consolidation and set-up, This was clearly demonstrated by the Harvey and Empire tests.
Recycling of Larger Offshore Facilities: Relocation of /W.C. 547 "A" Platform to E.C. 278 "C"
Authors: Disher A. , Maddox J.L.
Published: October 2008

The intent of this paper is to document the major accomplishments in the salvage, transportation and reinstallation of a 120 MMCFD gas drilling and production platform from one location in the Gulf of Mexico to another. The project entailed moving a complete 192' depth facility including jacket, deck, and process equipment. The paper Will discuss several Gulf of Mexico firsts for Texaco, such as:Heaviest jacket relocation in the Gulf of MexicoFirst upright lift and tow of a large jacketApplication of the Jones Act and impact on projectIn situ coating of splash zone area of structure

INTRODUCTION

The oil industry has always looked for more cost and time effective methods for developing deposits of hydrocarbons found beneath the Outer Continental Shelf (OCS). One method which has been used successfully is to drill the required wells from a fixed platform. This involves considerable lead time and cost to design, fabricate and install a structure and process equipment. After the hydrocarbon deposits have been depleted, the platform becomes a liability and must be removed and disposed of, often at greater expense than the original platform installation.

In 1988, Texaco successfully recycled an offshore platform, relocating the platform approximately 35 miles from a location with a water depth of 192 feet in West Cameron Block 547 (WC 547) to a location in 177 feet of water in East Cameron Block 278 (EC 278).

Production had ceased in WC 547 in February, 1987. Minerals Management Services (Ml&S)regulations required that this block be cleared of all obstructions within one year of the end of production or February, 1988. Texaco had a requirement for a platform to develop a separate prospect in EC 278. In May of 1987, preliminary engineering was started to determine if the WC 547 platform could be relocated to EC 278.

PRELIMINARY INVESTIGATION

Texaco was organized with the Offshore Division office, which included Engineering, Regulatory Compliance, and Legal Departments, in New Orleans and the Offshore District Office, which would perform all field work, in Morgan City. Texaco decided that the project manager would be in the Division Office and the project coordinator would be in the District office until contracts here signed; then the project manager and project coordinator would switch titles. Both positions were filled at Project conception, and the same personnel stayed with the project for the duration of the project.
The Deepwater Pipeline System on the Jolliet Project
Authors: Tillinghast W.S.
Published: October 2008

This paper describes the design and installation of the deepwater pipeline system which transports the oil and gas production from Conocors Jolliet Field in the Gulf of Mexico. This pipeline system used 12 miles of flexible pipe and 42 miles of conventional rigid steel line pipe. The pipeline system has pipelines in water depths as deep as 1760 ft. and as shallow as 230 ft. The paper describes the installation of flexible pipe risers at the TLWP, the laying of flexible pipe through rough seafloor conditions, the installation of rigid steel pipes in 1400 ft. water depth, and a seafloor connection system to facilitate tie-in of future production.

INTRODUCTION

The deepwater pipeline system for Conocols Jolliet Project required the use of many different aspects of offshore pipelining. The project involved two distinctly different pipeline systems - a flexible pipeline system and a conventional rigidsteel line pipe system. Each system presented its own particular challenges.

The complete pipeline system installed by Conoco for the Jolliet Project required the installation of a total of 54 miles of both steel and flexible pipe. The conventional steel line pipe system crossed 42 miles of varying sea bottom terrain. These pipelines started in 1080 feet of water and traversed through 1400-foot depths as the pipelines climbed up the continental slope to a fixed platform in 616 feet water depth. From there, the oil sales pipeline continued northward into slowly decreasing water depths to terminate with a subsea tie-in into an existing oil transportation system. These pipelines encountered a multiplicity of different situations: an undulating seafloor which created the potential for long pipeline spans, water depths to 1400 feet, rocky seafloor outcropping, pipeline crossings, subsea faults, laying lateral tap valves, deepwaterJ-tube riser pulls, and a subsea pipeline tie-in.

The flexible pipeline system used relatively large 8 inch and 10 inch inside diameter flexible pipes in water depths to 1760 feet. A total length of about 12 miles of flexible pipe was installed. Catenary riser configurations were used by the flexible pipes at the Jolliet Tension Leg Well Platform (TLWP). These risers were installed throughpull tubes on the exterior of a column of the TLWP. The flexible pipe was laid around and, in some cases, over areas of rough local microtopography. The flexible pipes were connected to the steel pipelines and connected to an underwater connection skid using saturation divers working to depths of 1080 feet.

GENERAL DESCRIPTION OF THE JOLLIET PROJECT

The Jolliet Projectl accomplished a full-field development to extract oil and gas reserves from Green Canyon Block 184 in the Gulf of Mexico. The development consisted of a Tension Leg Well Platform (TLWP) in 1760 ft of water in Green Canyon Block 184 with 20 TLWP production wells, a Central Production Platform (CPP) in Green Canyon Block 52, a Drilling Platform (52A) which is part of Conoco?s Marquette Project and is bridge connected to the CPP, andintra-field and export pipelines.
Inhibition of Sulphate Scale Nucleation
Authors: Pritchard A.M. , Buckley L.C. , Smart N.R. , Webb P.J.
Published: October 2008

The nucleation of (Ba, Sr)S04 scale has been studied on different surfaces representative of those likely to be encountered in oil production. The amount of scale formed and the efficiencies ofthree typical scale inhibitors depended on the surface used. Similar results were obtained from mixtures of seawater with either synthetic or real formation water.

INTRODUCTION

Mineral scales are frequently formed in oil production, usually as the result of changes in the temperature or pressure of produced fluids, or the mixing of incompatible formation and injection waters. The scale may form a precipitate in thebulk fluid, and be carried along with it in suspension, or it may nucleate on the walls of containing vessels and grow to form an adherent scale. This adherent layer can reduce the flow of fluids in tubulars, prevent the proper functioning of chokes and safety valves, and concentrate some radioactive species from produced fluids to an extent sufficient to create a local radiation hazard. Some of the suspended scale may betransported to the walls to form a particulate deposit that is more porous, mechanically weaker, and easier to remove than those formed by direct nucleation on the surfaces.

Despite the widespread occurrence of scale in oil production and other industrial and domestic situations, relatively little attention has been paid to the distinction between adherent and non-adherent scale. This paper describes some of the work being undertaken on scale nucleation on surfaces, and the effects of scale inhibitors on its inhibition and growth, in an on-going research programme at Harwell, supported by a number of oil producing companies. In view of the preponderance of mixed barium and strontium sulphate scaling in North Sea oil production as a result of mixing formation waters and seawater1, work has concentrated on (Ba, Sr)S04 scale formation on a number of surfaces representative of those likely to be encountered both downhole and topside.

THE NUCLEATION PROCESS

Nucleation of solid deposits is likely to be affected by the nature of the surface involved. The free energy change for the formation of a solid particle in a liquid can be written as(Available In Full Paper) where ø the driving force for the phase change, is given by(Available In Full Paper) in which S is the saturation index or saturation ratio, n is the number of molecular units in the particle,? the surface energy of the particle and A its surface area2. The change in G as the part1cle grows is given by(Available In Full Paper) where ? is the molecular volume and r is a measure of the radius of the particle that also allows for its shape. This change in free energy is thus affected by the saturation ratio, which isdetermined by the chemical composition of its surroundings and their temperature and pressure, and the energy required to create the new surface.
Diverless Pull-In, Connection, Service, and Testing of a Subsea Production Flowline
Authors: Webb P.H.
Published: October 2008

This paper reviews the development, for BP Exploration 'DISPS' Project, of two tools to perform the pull in, testing and connection of a subsea production flowline without the aid of diver intervention. Information is provided on the design, manufacture and factory testing of the two tools by Cameron Iron Works Ltd, Leeds.

INTRODUCTION

One of the objectives of BP Exploration's DISPS project was to perform dry testing of diver less tie in techniques, as part of its development of diverless flowline systems of 4 - 12 inch diameter pipes in water depths of 350 - 750 metres. This paper describes the design, manufacture and factory test undertaken by Cameron Iron Works Ltd, Leedsof two remotely operated tools for use in tying in a flowline to a subsea structure by three techniques, namely:Direct pull-inLateral deflectionVertical stab and hinge over.

The first two methods are similar in their requirements in that a cap is required to be fitted to the outboard flowline hub, which allows a cable to be attached to the front of the flowline pullhead. This is then used to pull the flowline into the correct alignmenton the subsea structure. The third method employs a hinged funnel permanently attached to the subsea structure into which the flowline is stabbed.

With this system the flowline is aligned when the funnel swings down during layaway - thus not requiring a pull in operation. All threemethods require the pull-in tool to be able to pressure test, pig and remove (or replace) the cap from the outboard flowline.

To achieve these functions four main pieces of equipment were required:-A piggable termination cap.A pull in tool.A connection tool.A clamp connector.

Ancillary equipment needed were the Inboard and outboard hubs (including handling rings), shipping bases and protection caps for the inboard flowline hub. The general connection system is shown in Fig. 1 and isdesigned for an 8 inch diamater flowline. However it can be adapted to operate on 6" to 12" pipes.

PIGGABLE TERMINATION CAP

This is a pressure containing vessel which comprises a flowline collect connector, a pull in cable release latch, access for pressure testing and a two stage valve for flooding and pigging operations of the flowline (see Fig. 2). Connection to the Outboard flowline hub is made by the collet segments which are clamped onto the hub flange and released by movement of an actuator sleeve through a handling ring.

A wedge action between the actuator sleeve and collect segments produced by movement of the sleeve opens or closes the segments. When fitted onto the outboard flowline hub, axial movement of the actuator is prevented by shear pins.

A pressure test can be performed with an Hydraulic Pressure Test Stab on the pull in tool, which opens a pressure balanced piston to uncover radial ports connected to the main body cavity. This can then be pressurised via the pull in tool umbilical line.
Settlement of Mat-Supported Mobile Units in Very Soft Clays
Authors: Cox W.R. , McClure S.C. , Sorensen K.H.
Published: October 2008

The behavior of a mat-supported mobile rig founded on very soft clay has been examined. The settlement of the mat into the clay during preload when setting up on the location is used to arrive at the ultimate bearing capacity of the soil. Analyses are then made of the bearing pressure of the mat on the soil when the mobile unit is subjected to storm loadings and these bearing pressures are compared to the ultimate soil beam pressures generated during settlements that accompanied preloading. This comparison provides guidelines for predictions of additional settlements that may occur under the storm loadings. The method putting bearing pressures under storm loadings is unique is that it considers elastic-plastic response of the soil resistance as contrasted to conventional elastic solutions or equivalent-area solutions.

INTRODUCTION

The first mat-supported submersible mobile unit, as reported by Howe (1966), was the Barnsdall-Hayward Breton Rig 20, later known as Kerr-McGee Rig 40 that was completed in 1949. Many years before the advert of the submersible rig, there were units known as marine drilling rigs that operated in lakes, bayous and dredged canals. These marine rigs were used offshore beginning in the late 1940's, and they were often founded on shell pads to increase their operating water depth. The submersible mobile units and the marine drilling rigs share one common feature: the large area of the mat permits the units to operate with minimum settlement, even on some very soft clay bottoms.

Hirst et al (1976) have reported that the average seafloor contact pressure of mat-supported mobil units is approximately 50 psf when there is no wave loading. They also reported no significant settlement of the rigs as long as clay bottoms had shear strengths of 100 psf or greater. For very soft deltaic clays with shear strengths of 40 to 50 psf, settlements do occur under contact pressures of 500 psf. A handful of clay soil with 40 to 50 psf shear strength can easily be squeezed between the fingers.

To control settlement in very soft clay bottoms a planned preload is applied when setting up the unit on locations, Turner et al (1987). As the mat settles into the seafloor under the preload, additional bearing capacity is developed from three sources: the increasing strength of the soil as the mat goes deeper, the increased buoyancy from the displaced soil, and the increasing friction of the soil on the sides of the mat.

Young et al (1981) have presented an extensive discussion of foundation performance of mat-supported mobile units in soft clays.
An Investigation Into the Effects of Using a Pit To Simulate Deep Water for a TLP Model Test
Authors: Murray J.J. , Mak L.M. , Sullivan M.A. , Winsor F.N.
Published: October 2008

A test program has been carried out on a 1:50 scale model of a 150,000 tonne tension leg platform in a water depth of 350 m. The same model was tested under the same wave and wind loading conditions in two separate facilities. The first was a 200 m by 12 m tow tank having a water depth of 7 m (350 m full scale). The second facility was a 75 m by 32 m basin having water depth of 2 m (100 m full scale) with the additional 5 m (250 m full scale) accommodated using a pit. The paper compares results found in the tow tank and those found in the basin. Presentation is based on comparison of the tether tension and rigid body motion response of the TLP to a number of wave and wind spectra simultaneously applied to the model. These results are also compared to numerical predictions.

INTRODUCTION

The tension leg platform (TLP) is one of the most popular concepts in compliant offshore structures employed in water depths ranging form approximately 100 to 1500 meters. The TLP, similar in appearance to a semisubmersible, is characterized by its vertical tethers (or legs) kept taut by excess buoyancy in the floating structure. The objective is to eliminate heave, roll and pitch motions of the platform by taking the associated loads axially in these vertical legs. The platform does however experience motions of surge, sway and yaw.

Among other considerations, hydrodynamic analysis of a TLP is concerned with response of the platform in terms of its motions, and response of the tethers. Normally, in the shallower range of water depths the tether dynamics are assumed to be very small and have negligible effect on the platforms motion, whereas the platform motion is the primary source of excitation to the tethers. In deeper water, tether dynamics can be significant. In this case there are two main methods of analysis; one analyzes the tethers independent of the platform, while another considers the coupled response of the structure-tether system. Similar consideration is given to the riser system attached to the platform.

Scaled prototype modelling is normally used to investigate the behaviour of such structures. The primary objective is to subject a model to an accurate representation of the environment which the full scale version will encounter. Usually, the largest physical model possible is sought and choice of scale is governed by available water depth at a particular facility. Consequently, a problem associated with test facilities for model test programs is the water depth. Most facilities intended for deep water model testing are equipped with a pit extending below the main floor of the tank. This assumes that the floor is sufficiently deep to avoid interference with kinematics of water particles in the water column. These effects are significant when considering the model tether (or riser) responses.
Full-Scale Fatigue Testing of TLP Tendons
Authors: Fowler J.R. , Long J.R. , Albert J.W.
Published: October 2008

The design of TLP tendons and tendon connectors to resist fatigue failures requires consideration of many factors, such as mean and alternating stresses, cycles, welding, residual stresses, base metal fatigue, and weld profile control. Many assumptions are necessary to do this. This paper describes the development of a machine which can validate these assumptions by testing full scale sections of tendons to fatigue loadings similar to those seen in service.

INTRODUCTION

One of the significant design considerations of Tension Leg Platforms is potential fatigue failures of the tendons. [1]* Tendons have a high mean tension and experience a large number of primarily axial tension variations (bending is also present) throughout the design life. In addition, all tendons have welds which have a lower fatigue strength than the base metal. Many tendon designs also incorporate connectors which may result in additional stress concentrations.

Unfortunately, there is a relatively large amount of uncertainty in fatigue design. To account for this, API RP 2T [1] recommends that tendon components be designed for a life of 10 times the tendon design service life and this recommendation was followed in the Conoco Jolliet TLWP. [7] There has been a considerable amount of work done in developing and fatigue testing connectors for TLP tendons [3,4,5,6], but this work has been primarily analysis and testing at scales of 1/3 and less.

Aside from mean stress, alternating stress, and number of cycles (the effects of these variables are customarily accounted for in the fatigue curves), there are a number of factors which influence fatigue life. These are:Metallurgy of base metalWelds and post weld stress relief of residual stressesProfile control of weldsStress concentrations at connectors and weldsSize of structure and amount of material actually stressedCorrosion/stress corrosion; speed of cycles

With the exception of item 6, which is accounted for by cathodic protection, these factors are considered in design by accurate calculation of peak stresses and selection of a fatigue curve which accounts for items 13. Item 5, the size of the structure, is accounted for by the fact that the fatigue curve is a lower bound to actual test data taken from a large number of small test coupons.

However, this process has a number of assumptions and approximations which it may be prudent to verify based on the large amount of welds and connectors in tendons which are subject to fatigue and the relatively small amount of actual test data. For example, a TLP in 3000' of water with twelve tendons and a connector every 80' will have approximately 450 connectors and 900 circumferential butt welds to connect the connector to the base pipe. If a tendon has 100 square inches of cross sectional area and 1" long welds, there are about 90,000 cubic inches of weld metal in all the tendons. Most fatigue data is taken with specimens which are on the order of 0.25" diameter and with a cross sectional area of about 0.05 square inches.
Jackup Dynamic Stability Under Extreme Storm Conditions
Authors: Hambly E.C. , Nicholson B.A.
Published: October 2008

Jack-ups have been used extensively in the North Sea as mobile structures and have had a good safety record. This good record has given several operators confidence to consider using jack-ups for the more demanding roles of production for extended periods at deep water locations. This paper examines the margins of safety provided by current regulations for independent leg jack-ups, and argues that larger margins of safety are needed for the more demanding roles of production in deep water.

Safety margins against collapse are examined with dynamic time-domain analyses of the nonlinear interaction of structure and seabed under escalating storm loading. These analyses extend the work of Hambly, Imm and Stahl1. Analyses on a future generation of jack-ups for 120m water depth in the North Sea highlight the fundamental importance of spudcan embedment and horizontal resistance of seabed to sliding of spudcans.

SAFETY FACTORS

Current regu1ations 2–6 and assessment criteria7,8 provide protection to jack-ups against collapse by specifying minimum Safety Factors against particular design loading conditions. The regulations have to cater for a wide variety of units and conditions, and for this reason the definitions are kept relatively simple and have to be interpreted in a robust manner. The Safety Factor against overturning, for example, provides a degree of protection against collapse from a variety of mechanisms including foundation failure and leg breakage. One would not expect a jack-up to collapse by overturning bodily because it is not a rigid body.

The UK Department of Energy Guidance Notes2 (DEn) indicate that structures should be assessed for environmental loads which "shall not be less than those likely to be exceeded on average once only in any period of 50 years" (referred to here as the 50-year load). DEn2 and others3,7 currently permit Safety Factors against overturning to be as low as 1.1. If a jack-up really does have such a low Safety Factor under 50-year loading it is likely to have a Safety Factor of less than 1.0, i.e. be unsafe, under 100-year loading. This can be shown by reference to Table 1 which shows in columns 1 and 2 the increase of wave height in the North Sea with return period as indicated by DEn2. Column 3 shows the increase in wave overturning load on a jack-up leg associated with the increase in wave height in column 2. In particular the overturning load from a 100-year wave is more than 1.1-times the overturning load from a 50-year wave. Dynamic calculations described later for a whole jack-up, as opposed to static calculations for a single leg, also show that the total overturning moment from 100-year loading is more than 1.1-times the total overturning moment from 50-year loading.

The safety record for jack-ups in the North Sea has been good9 even though stability assessments have included minimum Safety Factors close to unity. This is because it has been extremely rare for units to be subjected to loading approaching the maximum design loading while standing in deep water.
Analysis of Vortex-Induced Motions and Drag for Moored Bluff Bodies
Authors: Halkyard J.E.
Published: October 2008

A method of analyzing the vortex induced motions of a moored bluff body is described. A general current profile is assumed. The technique is based on computing modal excitation and damping utilizing "strip" theory for application of empirical amplitude dependent lift and drag forces. The linear second order modal response equations are solved iteratively. The "strip" theory model applies excitation or damping forces dependent upon the local sectional properties and the corresponding reduced velocities. An example using a single degree of freedom model for a deep water tensioned buoyant tower (TBT) is included. Recommendations are made for expansion of a model to include the effect of vortex suppression devices, different shapes and spanwise correlation of excitation forces. Further collection of empirical sectional data is suggested.

GENERAL

As oil and gas field development moves into progressively deeper waters, interest in large floating structures to accomplish such development has grown significantly. In areas where periods of sustained, high velocity currents may be expected, such as the Gulf of Mexico where the loop current and its eddies hold sway, there is concern over predicting the behavior of, and drag forces on, large floating structures subjected to the type of "strumming" experienced by cables and risers subjected to strong currents which has been covered extensively in the literature.

Two structures for which this "strumming" or periodic oscillation associated with vortex shedding is of particular interest are the Spar, Figure 1, and the Tension Buoyant Tower (TBT) Figure 2, which are described in other papers at this conference. Both are large diameter (85 feet - 140 feet) deep draft (400 feet 700 feet) cylindrical floating structures capable of supporting drilling and production equipment to handle several wells and 40,000 - 50,000 barrels/day of oil production. The Spar is free floating, moored by a multipoint catenary mooring consisting of driven piles and wire rope anchor lines. In contrast, the TBT comprises a buoyancy module tethered to the seafloor by a number of steel pipe tendons bundled together as a central stem which locks into a base which is in turn fixed to the seafloor by driven piles. Other structures for which the strumming phenomenon is of interest are the semisubmersible and the tension leg platform.

RESPONSE MODEL

The Spar, TBT and similar structures may be expected to "lock-in" when the Strouhal frequencyfs= So*V/D(1) wherefs= frequency of vortex shedding from a stationary cylinderSo= Strouhal number (0.18 - 0.3 depending on Reynold's number)V= VelocityD= Diameter approaches the natural frequency of the rigid body motion of the structure. The relationship between Strouhal frequency (i.e. the frequency of vortices shed from a stationary cylinder) and the structural natural frequency, fn, is usually represented by the "Reduced Velocity",UR= V/fnD = fs/Sofn (2) wherefn= natural period of structure
Snorre TLP Topside Design
Authors: Nilsen G.B. , Gabrielsen I. , Graff O.
Published: October 2008

This paper gives a brief description of the topside facilities and integrated deck structure for the Snorre TLP which will operate on Block 34/7 in the Norwegian Sector of the North Sea. Features which contribute to safe, simple and weight/space saving solutions are presented. The paper addresses where new technology is applied to achieve the overall goal of optimizing platform topsides. Comparisons with conventional installations in the North Sea will be presented.

TOPSIDE DESCRIPTION

Topside Configuration

An integrated deck concept (Fig. 1) has been chosen for its cost and weight benefits. The rectangular deck - 124.5 m long and 92 m wide - has a total height of 15 m including a 2 m deep double bottom forming the cellar deck. The deck is cantilevered at either end of the TLP by 1l.5 m.

Three main deck levels constitute the overall deck layout: cellar deck, intermediate deck and upper deck. Local mezzanine decks have further been included for support of equipment and facilities.

The main structural girders comprise a combination of trusses and plate girders. The six open trusses form the longitudinal girders of the platform, whereas the plate girders span in the transverse direction, providing partitions between the areas. This gives a safe segregation of hazardous and non-hazardous areas. The intermediate and mezzanine decks are simply supported on the plate girders and contribute little or nothing to the global strength.

The cellar and upper deck sections have their structural configuration determined by the overall structure and contribute to the global strength.

The design of the deck sections has taken into account the requirements for fabrication, lifting, installation and reduction of the structural dead weight to a greatest possible extent.

The deck is constructed and assembled at a main site. However, the deck has been designed such that 17 of the deck sections can be fabricated and outfitted at other sites. These approximately 20 × 20 meters deck sections, or preassemblies as they have been called, were mechanically completed to the largest extent possible at the different yards before being transported and lifted into the main frame.

Topside Layout

The layout meets all of the operational design and safety requirements and at the same time conforms to the normal segregation of hazardous areas found on other Norwegian platforms. The facilities have been layed out in the following sequences (Fig. 2):Living quartersUtility areaDrilling facilitiesWellbay areaProcess areaFlare The main lifeboat station and the Living Quarter is located in the western end on a cantilevered portion of the deck at the maximum distance from the hazardous areas.

Adjacent to the living quarters is the utility area with main power plants and control rooms. Also the 4 × 50% fire water pumps are located in this area directly above the columns. The area adjacent to the utility area contains most of the drilling equipment and other utility systems.
Snorre Project Strategies and Status
Authors: Lappegaard O.T. , Solheim B.J. , Plummer F.B.
Published: October 2008

The Snorre development is one of the most challenging projects carried out in the Norwegian North Sea since the pioneering days of the early and mid 1970s. This paper summarizes these challenges and provides insights into Saga Petroleum's highly leveraged strategies for applying recent technology to develop this deepwater field. The field installations are described with emphasis on technical innovation. This theme is followed up, in more detail, in the other Snorre papers. The status of project manning, progress and cost is summarized as onshore fabrication nears completion.

CHALLENGES

The Snorre field is located west of the Norwegian trench approximately 26 km northeast of the Statfjord field. It is operated by Saga Petroleum on behalf of the nine other partners shown in Fig. 1. The reservoir and deepwater challenges on Snorre coupled with the turbulent oil price fluctuation of the 1980s have caused the project to seek and find innovative development solutions.

Reservoir and Reserve Challenges

The nature of the Snorre reservoir and the vast areal extent have made it necessary to drill a relatively large number of wells to develop the reserves. Compared to other large fields in the shallower waters of the Norwegian sector (Fig. 2), Snorre has lower reserves which are spread over the same area as Statfjord and Oseberg, and over a much larger area than Gullfaks. On the other hand, the number of wells which must be drilled is comparable. Thus, the reserves that can be recovered per well on Snorre are, on average, significantly less.

The reservoir is located about 2500 meters below sea level. It consists of two sandstone formations, the Statfjord (Jurassic) and the Lunde (Triassic). The recoverable reserves are:Oil - 122 million cubic meters (770 million barrels)Gas - 7 billion cubic meters (250 BCF)Liquids - 3 million tonnes. A total of 68 million cubic meters (430 million barrels) of oil will be produced during the first phase of development. This will be the first time that the Lunde formation has been produced.

In Fig. 3 a cross-section of the Lunde formation is shown through one of the more prolific areas. Most of the oil is located in the D, E, and F units. In the same manner as for the Statfjord formation, major faults with large throws divide the reservoir into fault blocks. Minor faults further subdivide the reservoir. The transmissibility of the faults is uncertain. The reservoir contains over-pressured, highly under-saturated oil. It must be developed by water injection pressure maintenance since no significant aquifer support is expected. The complex fluvial reservoir, low dip, and anticipated poor vertical communication were judged to be unsuitable for successful gas injection pressure maintenance. In addition, for the Lunde, the lateral continuity of the fluvial sandstones is considered to be limited.

In order to achieve a satisfactory level of recovery, water injection will take place from the start of production. The plan for developing the total reserves calls for 93 wells to be drilled.
Troll Oseberg Gas Injection (TOGI) Development
Authors: Boge M.
Published: October 2008

In 1986 the Oseberg partners decided to replace the planned water injection scheme by gas injection.

Pressure maintenance by gas of the Oseberg reservoir instead of water is estimated to increase the overall oil recovery by approximately 7% or 75 mill bbls. In addition 21 water injection wells are saved. Approximately 75% of the injected gas will be recovered.

The Troll-Oseberg Gas Injection (TOGI) development was initiated to supply gas to Oseberg from the nearby Troll field. The gas is produced by a subsea station with 5 wells, and transported unprocessed through a 48 km long pipeline to Oseberg.

The subsea station is remotely controlled and monitored from Oseberg.

This 3 bill NOK project operated by Norsk Hydro started production in January 1991 after 4 1/2 years development.

INTRODUCTION

In order to further improve the oil recovery from the Oseberg field reservoir an external gas supply for injection purposes was sought for to replace a planned and comprehensive water injection scheme for the Oseberg reservoir.

This triggered a study directed towards a deepwater development of part of the nearby giant Troll field gas reserves for injection gas delivery to Oseberg, 48 km away, for improved reservoir pressure maintenance.

The Troll-Oseberg Gas Injection (TOGI) development was initiated by Norsk Hydro and presented to the Oseberg and Troll field partners in the spring of 1986, and was met with their approval.

4 1/2 years of novel technology development, testing, installation and completion work has now passed and the TOGI development is preesently in operation and gas is being produced from the Troll deepwater station in 303 meters of water by the Troll field licensees, and transported and sold to the Oseberg field licensees to enhance the Oseberg oil recovery with approx. 7%.

Two percent, up to one trillion scf. of the large Troll reserves will be injected into Oseberg over a twelve year period. 75% of this gas will be recovered and sold after year 2002, when Oseberg goes into its gas production phase.

This paper will addressThe impact on Oseberg of gas injection vs. water injection.A brief presentation of the contractual agreements between the two license groups.A conceptual description of the TOGI development.a presentation of TOGI project contracts and organization principles. Norsk Hydro is the operator of both the Oseberg project and the TOGI project.

This paper is one in a series of six which are presented at the OTC 1991.

Impact on Oseberg - Advantage of Gas Infection

The Oseberg field is located approximately 140 km west of Bergen, Norway, fig. 1. The phase I development of this field consisted of a field centre (the 'A' and the 'B' platforms), an oil pipeline (28") to shore and an oil terminal onshore for storage and export of the crude oil. Phase I also included two subsea wells.

The main Oseberg reservoir is split in three different structures, the Alpha structure, The Alpha North structure and the Gamma structure, fig. 2.
Subsea Processing and Control System in the GA-SP Project: Testing of the Prototype System
Authors: Nordvik H.S. , Sarshar M.M. , Taylor M.
Published: October 2008

The subsea production and processing developed under the "GA-SP" project involved two stages of separation, leading to production of exportable quality crude oil by pipeline. The produced gas is transported along a separate line. Key elements of the subsea process system are described in this paper. A prototype system was developed during the second phase of the project. This system was tested under dry and submerged conditions in a drydock. Key features of the prototype system and the tests earned out are described. Prototype testing has proved the viability of the GA-SP system and has helped to identify areas requiring particular attention and improvement for future field applications.

1. INTRODUCTION

The main objective of the GA-SP project has been to develop a subsea production system suitable for the development of satellite marginal fields. This was a joint industry project supported by the European Community and eight major oil companies, An overview of the system and the economics are addressed in a separate paper (OTC 6766). In this paper, some of the key features of the process and control system are highlighted with reference to the extensive testing of the prototype system.

The "Base Case" relates to a satellite field 30 km away from the mother platform. The field consists of four production wells and four water injection wells. A general view of the field scenario is shown in Figure 1.

Design Parameters

The main parameters for the design of the system are summarised in Figure 2. The sensitivity case shows the range of values of interest to the participating oil companies and does not reflect the limits for future field applications.

The requirements for the quality of the processed crude oil was not necessarily the minimum or optimum for the system but was set as a relatively more demanding case in order to export produced oil direct via an existing trunkline. The options for simplifying the process system are discussed in sections which follow. The high export pressure specified for the crude oil was to meet the operating pressure specified for the trunk line.

Process Flow Diagram (PFD)

Figure 3 shows the simplified process flow diagram. Two identical production trains are adopted. Each train serves two wells with an option to divert flow from one train to another via the test meter loop.

Production testing of individual wells is achieved via a by-pass valve leading to the test header. The multiphase test meter enables subsea measurement of individual wells without the need for a test line or a separate test separator.

The separator comprises two stages of gas/liquid separation in order to meet the specified TVP requirements. This leads to production of gas at different pressures (first and second stage separators). An ejector is used to commingle the gas products from the two sources for export via a single line. Oil and water are transported along separate lines for the Base Case. Separate booster pumps are used for each train.
Offshore Minerals in the 21st Century
Authors: Kallaur C.U.
Published: October 2008

This paper presents an overview of the marine minerals program as it exists today in the United States and what is envisioned for the future. It attempts to define a proper role for Government in a market economy that will allow private investment to occur if the market conditions are right. It outlines the program strategy followed by the Office of International Activities and Marine Minerals, Minerals Management Service, U.S. Department of the Interior, and focuses on the question of where the United States as a Nation may wish to be in the 21ST century with respect to a marine minerals program and what needs to be done to get there.

INTRODUCTION

To date, a viable marine minerals industry has' not been established in the Uni ted States. The lack of progress over the last 30 years in establishing such an industry has been well documented in the literature. The lack of progress directly contrasts with the experiences of the United Kingdom and Japan, which have had successful offshore sand and gravel development programs for over 30 years.

Following the establishment of the U. S. Exclusive Economic Zone (EEZ) in 1983 by Presidential proclamation, new opportunities appeared to exist for commercial development. The Minerals Management Service (MMS) of the Department of the Interior, which has the responsibility for managing the mineral resources on the Outer Continental Shelf (OeS) and the EEZ, responded by establishing an office specifically focused on the development of a marine minerals program. This office was originally named the Office of Strategic and International Minerals and has since been renamed the Office of International Activities and Marine Minerals (INTERMAR) to reflect a new responsibility for overseeing the international activities of the MMS.

In addition to the establishment of the EEZ, the renewed interest in a domestic marine minerals industry reflects the strategic importance of certain minerals, the decreasing availability of supplies of construction aggregate onshore and in coastal waters, and the economic benefits that could be reaped domestically if a successful program were established. Recent developments have also identified a widespread need for large amounts of sand for environmental restoration projects.

This paper addresses the possibilities for a domestic marine minerals program in the 21st century and the actions the Government should take to increase the chances of success. It explores the proper role of Government in providing the institutional framework that is necessary for the private sector to make investment decisions, including the removal of perceived obstacles to development. The success stories of other nations that have marine mineral programs may provide some examples. Defining a role for Government involves questions regarding the proper sharing of risk between Government and industry as well as an assessment of the strategic and economic importance of developing both minerals domestically and the required technology.