bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulated Turbulent Flow and Forces Around Groups of Cylinders
Authors: Hansen E. Asp , Yde L. , Jacobsen V.
Published: October 2008

Results from numerical simulations of flow at high Reynolds numbers around cylinders and associated forces are presented. The numerical model is based on the discrete vortex model combined with an integrated boundary layer model. Hereby it has become possible to include the influence of the pipe roughness on the flow and the associated forces. The paper summarizes the theoretical basis for the model, including the boundary layer part and a simple approach for including the diffusion of rotation. Results obtained from the simulations with arrays of 2, 4 and 8 cylinders are presented. Steady flow and oscillatory flow cases are covered.

INTRODUCTION

An extensive amount of experiments to determine hydrodynamic loads on single cylinders has been carried out and reported in the literature. Within the last decade or so, increasing attention has been given to the determination of forces on more complex structures, such as riser bundles (Ottesen Hansen et al /1/, Overvik et al /2/), conductor arrays (Heideman and Sarpkaya /3/), and the complex joints of steel jackets (Velk and Sterndorff /4/).

When a cylinder is located in the downstream wake of another the force on the rear cylinder is typically smaller than on the one in front. This phenomenon is often referred to as 'shielding effect'. If, on the other hand, the same two cylinders are placed side by side in close proximity, the total force on the two becomes larger than the sum obtained from two isolated cylinders. This is referred to as 'blockage effect' or 'negative shielding effect'.

Model tests and full scale measurements on jacket type structures have clearly demonstrated the shielding effects in steady current flows, see e.g. Lambrakos et al /5/, and Cuffe et al /6/. Reductions in total loads of up to 40 - 60 percent were found for structures with large conductor arrays. In wave flows, the shielding effects may be less significant, Cuffe et al /6/, Sterndorff et al /7/.

The blockage effect was demonstrated for the simple 2 cylinder case by Jacobsen et al /8/. A system with a small and large pipe in close proximity resulted in load increases of up to 85 percent as compared to a 25 percent increase in exposed area for the side by side arrangement. For the tandem arrangement the total load was smaller than the load on the large pipe alone.

For groups of cylinders it is not trivial to evaluate whether the total force becomes smaller or larger compared with the situation where the cylinders are separated. Depending on the flow conditions and flow angle a group of cylinders may exhibit increase as well decrease in load compared to the separated cylinder case. Individual cylinders in a group will experience reduced load, others increased load. Detailed analyses and testing are required to assess the loads on cylinder groups.

In the present paper numerical results are presented for total and individual loads for systems containing 2, 4 and 8 cylinders.
Design of Gas and Oil Riser Installations for Offshore Platforms
Authors: Coker J.W.A.
Published: October 2008

The Piper Alpha (ref. Ocean Industry Jan 1991) accident has focused attention on the design of riser installations offshore. As shown in this incident two major factors must be considered when designing riser installations. These are:to reduce the possibility of a dangerous event on a platform affecting the risersto reduce the consequences to an acceptable level if a riser failure occurs. There are many ways to design the installation so that the safety is at an acceptable level but this can be very dependant on the type of platform and function. The riser installation could, for example, be different if a concrete substructure is used instead of a jacket substructure.

This paper will indicate the various riser schemes used on installation today, outline the riser installation philosophy adapted for the latest Statoil designed platform and discuss how further installations can be designed to ensure acceptable safety at minimum investment cost.

INTRODUCTION

The risk associated with offshore installations for the production of oil and gas can, in principle be, divided into various risk areas. Different criteria can be used for the risk to personnel, the environment, or the risk to the capital investment. The risk can also be divided into the risk from design accidental events and residual events. The design accidental events are scenarios that the installation is designed to survive with acceptable damage to the personnel protection systems or/and the investment. The residual events are scenarios where it is likely the installation will suffer major damage or total loss.

The installation and equipment should therefore be designed such that the probability of the residual event is as remote as possible, within reasonable financial and practical considerations. The acceptance criteria must be decided on a company to company basis.

From the various studies carried out, which are backed up by the statistical data, the indication is that two types of platform (onboard) incidents can result in total loss of the installation. These are loss of control over the production wells and failure of the gas or oil risers. Both these type of events could lead to large releases of hydrocarbons over a long period of time.

The arrangement and design of the risers is therefore an very important parameter that must be considered during the design of offshore installations. With careful design it is possible to reduce the probability and consequence of a riser failure to a minimum, and to ensure the incident is contained into one area of the installation, at least for the time to allow safe evacuation of personnel.

RISER INSTALLATIONS ON EXISTING INSTALLATIONS IN THE NORTH SEA

Most of the early installations in the North Sea used a steel jacket design where the riser(s) was clamped to one of the main legs (ref. figure 1). The location of the riser was often decided by the arrangement of the process or metering systems.
Analysis of Platform Collision Chances
Authors: Massie W.W. , Buijs A.H.E.
Published: October 2008

The chance that a fixed platform is rammed by a passing ship is studied via the use of a fault tree of events which lead to collisions - caused either by technical or navigational failures. It is found for the North Sea that the chance of a collision can be appreciable for a platform located near a busy shipping lane but relatively insignificant for a platform in an isolated location, far from shipping lanes. Appreciable in this context describes a chance comparable to that of a major fire on an offshore platform.

Old and flag of convenience ships are involved in most of the collisions. It is impractical to close the North Sea to all such ships, even though this would reduce the risk of collisions by more than a factor of 2.

In the course of the literature survey, it was found that many mariners use charted offshore platforms as navigational aids; they therefore approach close to them for the sake of positive identification. One practical means of reducing the chance of collisions would be to install racons on each platform so that they could be identified on a radar screen from a distance; this would alleviate the need for this close approach.

A second effective approach is to install a traffic guidance system for groups of platforms near busy shipping lanes. Experience with such a land-based guidance system in the Dover Strait has been very rewarding.

INTRODUCTION

Collisions have occurred between passing vessels and offshore platforms for some time. In the North Sea, a fixed structure in Dutch waters which had just replaced a lightship was rammed by a coastal merchant ship in the late sixties. A more bizarre accident occurred in the eighties when a submerged German submarine rammed a fixed platform in the Norwegian portion of the North Sea. While designers obviously know that a finite chance exists that a platform will be hit by a passing ship, the systematic quantification of this chance has been neglected.

All marine catastrophes (including collisions) can lead to any combination of the following three types of risk: to persons - either those directly involved or as by-standers such as yachtsmen, to property, or to the environment. In another approach, the significance of various risks in the eyes of the public varies depending upon several factors. These are explained in more detail in an appendix derived from [1].

METHOD

Unfortunately, direct data on the risk of collisions between passing ships and offshore structures is incomplete and therefore of limited usefulness; a direct approach by a statistical analysis of data such as that available in [2] will be disappointing, therefore.

An alternative to this direct approach must be found. The alternative chosen for this work was to start with statistical data on ship operational details (such as not having adequate charts on board) and - using this data - construct a fault tree for events which could lead to a collision.
Kittiwake Loading Buoy (KLB): A New Lease on Life
Authors: Vogt C.
Published: October 2008

A large loading buoy, installed for 14 years in a North Sea field, was converted, incorporating the latest technology and operating experience, for a new application as the sole offloading facility in a newly developed oil field. In spite of a significant design change to the mooring of the system the buoy body of approximately 800 tonnes could be reused for 30 more years of service life. An expensive upending operation was avoided by an inshore conversion, executed afloat at a sheltered deep location.

INTRODUCTION

North-Sea oil fields started to be developed some 20 years ago with production platforms. None of the first platforms contained any storage for the produced oil and as pipeline construction was not advanced, efficient offloading into shuttle tankers became a vital requirement. First installations used the conventional CALM buoys which required improvement to cope with the especially harsh environment of the North Sea.

The first tailor-made offloading buoy was conceived and installed in the AUK-Field in 1974, called the ELSBM (Exposed Location Single Buoy Mooring) -> (See reference OTC-Paper 3805).

The ELSBM was in service in this field until 1988, initially operating as the sole system which allowed oil export and towards the end as a stand by system after the tie-in to the FULMAR-Field.

The Operator SHELL-EXPRO, who was preparing the development of the Kittiwake Field, decided to look at the feasibility of reusing the available and redundant ELSBM in this new field.

Engineering of improvement, based on operating experience and implementation of features developed for other offloading systems in the North Sea, were contracted by the Operator in early 1988 to Single Buoy Moorings Inc., whose sister company Gusto had built the original system.

The ELSBM was converted accordingly and is now in operation providing offloading of all produced oil from the Kittiwake Production Platform into shuttle tankers. The refurbished buoy is called KLB (Kittiwake Offloading Buoy).

DESCRIPTION OF ORIGINAL AUK-BUOY (ELSBM)

The ELSBM consisted of along, slim, cylindrical buoy with a diameter varying from 8.6 to 12 m and a draft of 52 m. It was anchored to the sea-bed with an eight chain pattern of 3" size chains. A large fender structure with rubber fender elements and wood protection surrounded the top of the buoy providing protection from supply vessels.

A rotating head, permitted weather-vaning mooring and contained storage reels for a single 10" offloading hose string and a mooring hawser. A helideck allowed access for maintenance crew visits.

A 50,000 DWT passive tanker could be moored to offload in sea states of up to 3.6 m significant waves.

The activation of the hose and hawser reel was by a counterweight descending into the center well of the buoy via pulleys and steel cables. The shuttle tanker had to fish a floating pick up line out of the water and then un-reel the hose and mooring hawser by heaving in on this line.
Offshore Sulphur Production
Authors: McKelroy R.S.
Published: October 2008

INTRODUCTION

Sulphur is an abundant element that has been used by man since ancient times and is today a key basic raw material for the modem chemical industry. The invention of the Frasch hot water mining process in the late 1800's gave the United States a plentiful low cost supply of pure sulphur. The Frasch process makes possible the mining of sulphur from the limestone caprock of offshore salt domes. The latest of these mines is the Main Pass Mine located on Main Pass Block 299 approximately 36 miles east of Venice, Louisiana.

BRIEF HISTORY OF SULPHUR

Sulphur, in the form of sulphides, sulphates, and elemental sulphur, is one of the more abundant elements in the makeup of this planet, ranking eighteenth behind chlorine. The sulphides are among the most common minerals pyrites, galena or lead sulphide, zinc sulphide, and cinnabar or mercury sulphide. Vast beds of gypsum or calcium sulphate are found all over the world, and barite or barium sulphate is widely mined is several countries. Sulphur also occurs in elemental form imbedded in limestone caprock over salt domes, in craters of volcanoes, and encrusting the edges of hot sulphur springs. In addition to the sulphur in caprock limestone, it also occurs in strata bound layers of limestone such as the deposits in West Texas, Poland, Iraq, the Ukraine, the Sinai, and Sicily.

This bright yellow substance that burned with an odd sputtering blue flame, and giving off evil, choking fumes was one of the first elements used by man. Early priests and witch doctors burned sulphur to drive away bad spirits. Later man learned that sulphur fumes would kill insects and take the color out of fur, feathers, and wool. In the ODYSSEY Homer mentions the use of burning sulphur to cure ills and to avert pests. The primary use of sulphur for the past 250 years has been in the production of sulphuric and sulphurous acid. The first production of sulphuric acid in America took place at Philadelphia in 1793 where John Harrison produced 45,000 pounds by burning sulphur in a lead lined box and collecting the fumes in water. The modem chemical industry was born in 1823 when a soda alkali plant using the Leblanc process was built at Liverpool, England. This process starts with the decomposition of common salt by sulphuric acid. The start of the soda alkali industry thereby established a strong demand for the sulphur to produce the required sr, dphuric acid. The bulk of today's sulphur production is used by the fertilizer industry to produce sulphuric acid which is reacted with phosphate rock to produce phosphoric acid, the source of the phosphates in fertilizer.

Sulphur consumption has, for many years, been recognized throughout the world as an index of a country's industrial development and the extent to which its industrial capacity is utilized. About one hundred years ago, Herman Frasch provided momentum to industrial expansion by developing the Frasch process for mining sulphur horn the salt dome deposits along the Gulf Coast.
Field Experience on the Inspection and Performance of Subsea Pipeline Cathodic Protection Systems
Authors: Rippen I.J.
Published: October 2008

DPC has one of the most complex offshore pipeline systems in the world. The field is mature with many of the pipeline CP systems at or approaching the end of their life. A regular inspection program has to be set up to monitor these systems. With good historical inspection data, future inspections are now based on the condition of each individual CP system, rather than carried out at fixed time intervals. This has resulted in significant cost savings. Premature depletion of the pipeline anodes has been seen which is due to a number of factors, including the interaction of pipeline and platform CP systems. With careful planning this same interaction can be used to reduce anode retrofitting costs on pipelines. This has only a marginal cost benefit to DPC, but will have a significant cost benefit in other areas of the world where diving conditions are more severe.

Introduction

DPC operates one of the most complex offshore areas in the world, in terms of number of platforms and number of pipelines (Figure 1). There are 2 main fields, Fateh and South West Fateh and 2 smaller fields, Falah and Rashid. The fields are characterized by a large number of jackets in relatively shallow water linked by short in-field pipelines (typically 10,000 ft.) carrying waterflood water and gas lift gas to the platforms and produced fluids from the platforms. The fields are linked by longer transfer pipelines (typically 40,000-50,000 ft). In total there are 76 jackets. Water depths vary from 100 ft to 191 ft with an average of 144 ft. The oldest jackets and pipelines are 22 years old. There are 112 pipelines in service, with a total length of 276.7 miles. Line sizes range from 4" to 42", with the majority of the lines in the 12" to 18" range.

Cathodic Protection Inspection History

Early Life of the Field

Originally all the pipelines were electrically isolated from the platforms, using insulation flanges. The platforms and pipelines are protected by sacrificial anodes. As these systems were then relatively new, the levels of cathodic protection (CP) were good. Annual dip check readings were started on the platforms, taking readings on each leg and on each riser. Due to the risks of entanglement of the reference electrode lowered in the water with the jacket structural members, readings were only taken down to -25ft.

Over a period of time shorting occurred over the insulation flanges, such that pipeline anodes were protecting platforms and vice versa. Whilst it is not cost effective to have pipeline anodes protecting platforms, in a few instances this was certainly the case. The first platform, "C", was retrofitted in 1983 (ref. 1). The CP system on "C" platform was designed for a 10 year life; after 15 years the potentials were -940mV (ref Ag/AgCl), with most of the anodes totally consumed. The platform was being protected by the pipeline anodes.
The Further Development of the Ekofisk Field: "In-Fill" Drilling Taken One Step Further
Authors: Croucher T.M.
Published: October 2008

This paper reviews the planning, preparation and initial implementation of drilling operations for the latest phase of development of Phillips Petroleum's Ekofisk Field in the Norwegian Sector of the North Sea. This development includes the addition of 32 new production and injection wells to the existing t 80 well field. The unique aspect of the project was that, at the time of conception of the project, only 8 spare slots were available on existing structures, and preliminary economics proved the addition of a new structure unfavorable. The decision to utilize existing structures for the additional wells created many challenges for Phillips Petroleum Norway's engineers and this paper describes a number of the more interesting and unexpected of those challenges and their solutions.

BACKGROUND.

The Ekofisk field is the largest of the Phillips Norway Group's seven field " Greater Ekofisk" operation, located in the south west corner of the Norwegian sector of the North Sea. An overview of the " Greater Ekofisk" infrastructure is shown in fig.1. The Ekofisk field itself now comprises three production and two injection platforms, as well as eight other accommodation, process and transportation facility platforms.

Production from the Ekofisk field peaked in 1980 with production figures of 618rO00 BOPD and 1,860 NMSCFD of gas. production decline, led to the evaluation and pilot study of a field water injection program. In 1986, the Ekofisk field water injection program commenced from the 2/4 Kilo injection platform (30 well slots capacity). Water injection into the Ekofisk reservoir reached 375rO00 BWPD in 1990 into a total of 20 wells.

Positive results prompted Phillips to evaluate further development of water injection coverage, as well as adding producers to optimize recovery from the reservoir. The location of 2/4 Kilo, near the north end of the Ekofisk field, limits access to the center and south end of the field for injection purposes. Also, in 1986r nearly all 56 well slots located on the three Ekofisk production platforms, 2/4 Alpha (16 slots), 2/4 Bravo (24 slots) and 2/4 Charlie (16 slots) had been utilized. As a result, studies were initiated to evaluate the options for increasing the number of well slots at different locations in the field. Various scenarios were considered including new wellhead platforms, cantilever extensions to existing structures, and modifications to existing facilities. The decision was finally made a) to modify two of the existing production platforms (2/4 Alpha in the South of the field, and 2/4 Charlie near the field center) to add eight extra well slots on each structure, and b) to modify one of the bridge support tripods at the south end of the Ekofisk complex to accept a wellhead module for eight water injection wells. The location of the bridge support was ideal, in that it gave access to center and southern areas of the field for improved water injection coverage. The new injection platform was assigned the designation - 2/4 W.
A Design Review of Diverless Subsea Production Systems
Authors: Rodda N. , White J.
Published: October 2008

The paper presents a design review of major diverless subsea development schemes covering concept, prototype and live installations. The paper describes the main features and maintenance intervention philosophies of these developments and highlights those design principles developed in the last decade which are likely to be in use during the early 1990's.

Several distinct development themes are identified in the paper including: the use of established drilling technology as a means of retrieving modules; the use of special purpose remote vehicles to retrieve modules or single components; and the use of commercially available ROV's to replace individual components. Each of these main intervention methods can be applied to diverless subsea developments.

INTRODUCTION

This paper which is based on work undertaken by Fuel Subsea Engineering Limited for BP Exploration reviews the design of diverless subsea systems over the last decade to provide a historical context for those engineering issues which will shape current and future development plans.

The scope of the review was not unlimited and therefore criteria had to be established for identifying systems to be considered; these areSystems in productionSystems under developmentConceptual systemsSystems on a global basis The review identified differences and similarities between the diverless subsea system designs by assessing each system in terms of the overall system design and in terms of major subsystems, via:Overall system philosophy and configurationFlowlinesManifold/TemplateXmas treeControl systemMaintenanceIntervention vehicles Eighteen systems were investigated in some detail and a further five systems considered briefly. The systems considered are shown by geographical location in Table 1.

The review of each system was based on the most recent data available in the public domain during the research period. Direct contact with relevant operators, authors or design contractors was not made and therefore it was not possible to verify the published data.

Data sources reviewed were technical proceedings from various conferences including Offshore Technology Conference; Offshore Europe Conference Underwater Technology Conference; offshore Northern Seas Conference; and Deep Offshore Technology Conference and other technical publications, including magazines. The number of individual references was extensive, with over 60 papers being reviewed in the course of the work. For this reason individual references are not given in this paper.

OVERALL SYSTEM PHILOSOPHY AND CONFIGURATION

Reservoir and economic factors are the primary aspects in determining whether a particular hydrocarbon field has the potential for development by subsea means. Once a subsea system is to be considered, the way in which the system is to be installed, operated and maintained is the most significant technical issue. However, there have been almost as many technical solutions proposed as projects undertaken. This lack of consistency is due to the evolving nature of the industry, which has yet to 'mature'.
A Proven Oil/Water/Gas Flowmeter for Subsea
Authors: Martin W.W. , Woiceshyn G.E. , Torkildsen B.H.
Published: October 2008

A static mixing device was tested in combination with a dust-energy gamma volume fraction meter and a venture meter in order to determine if this combination could be used to reliably measure oil-water-gas rates under flow conditions typical for offshore oil and gas production especially in the North Sea. A high-rate test facility was used to circulate oil, water and air or nitrogen at rates of up to 60 m3/hr(l 0000 bbl/d) of liquids and total flow of up to 200 m3hr(30000 bbl/d). The tests were carried out primarily in the unsteady slug and bubble flow regimes with gas volume-fraction up to 100 percent and water-oil ratio up to 60 percent. In order to estimate the accuracy of the meter system under test, the single-phase flow rates of the three components were measured independently upstream of the mixing unit which was placed directly upstream of the dual-energy gamma and venture meters.

The results of the tests carried out with and without the mixing unit show that the mixer eliminates the slip between the gas and liquid phases well enough to obtain repeatable estimates of oil and gas volume fractions within ± 10 percent relative error over the entire range of conditions tested for fractions over 30%. Oil flowrates were also measured to within an accuracy of 10 percent compared to the independent single-phase rates over a wide range of conditions up to percent 70 percent gas volume.

No attempt was made in this study to optimize the performance of the combination of the mixer and two meters but the test results and experience indicate scope for improvements to the arrangement between these three main elements and to the dual-energy gamma technique itself. In addition, a follow-up feasibility and pre-engineering study was carried out to establish design criteria for a subsea meter based on the tested technologies. A prototype subsea meter is under design and further testing is expected to begin late in 1991 in the current phase of the project.

INTRODUCTION

The measurement of oil-water-gas production rates by means other than test separators has been a subject of intense research end development because of its potential to eliminate the need for test separators on platforms, to supplement test-separator capacity for satalite developments and for reservoir monitoring. Many methods based on various physical phenomena (such as gamma-ray attenuation, microwave, capacitance)have been tested with varing degrees of success depending on the composition, flow rates of the phases and flow regime or pattern. In all the cases reported where it is attempted to measure the flow without first separating the phases, slip between the phases causes errors which are too large (much greater than 10 percent) to be considered useful for the range of operating conditions that can be expected for typical offshore wells. In those cases where initial separation of the phases was undertaken prior to single or two-phase measurements, additional uncertainty and/or complexity is introduced which limits the usefulness this approach.
A Computer Program To Analyze Suction Effects
Authors: Christensen N.H. , Haahr Frands
Published: October 2008

An algorithm was developed to evaluate the pull-out capacity or resistance of open-bottom or closed cylinders under water and embedded in the sea floor, with full account of suction effects. The basic mechanics are very simple, but the combinations of geometry, soil conditions and failure modes are legion.

The method provides for easy parameter studies and thus for an optimal use of the suction effects in the design of small offshore platforms, submersible CPT-rigs, suction anchors for mooring buoys, etc. It works as a small 'expert system' and needs very little computing power.

INTRODUCTION

Attempts to analyse the installation procedure and the pull-out capacities for suction piles showed so many variations that it became advantageous to use a computer.

It was first required to analyse the pulling resistance of the three hollow foundation piles, open at bottom level, of a monotower offshore platform. For these piles, shorttime vertical tension (pull-out) forces are of particular interest. These forces are generated by a ship's impact or waves and vortex shedding on the superstructure.

The methods used in the program are presently being compared with conventional small-scale model tests as well as small-scale centrifuge tests. Lately also field tests on a larger pile model are planned.

There are various failure modes both for sand and for clay. These mechanisms will be mentioned as well as the main parameters which control the magnitude of the suction effect. The capability of the program will be visualized through the analysis of two structures for which the suction effects are essential.

PROBLEM INPUT

In addition to geometry, weight and shear strengths, certain assumptions concerning the suction effects are required. Various types of analysis may be used; of these the processing of test data will not be discussed.

Geometry parameters : The geometry parameters_ are defined on Fig 1. The vertical dimensions are the water depth, the total pile height, the penetration measured on the outer side of the pile, and the height of the soil plug in- side the pile.

For the horizontal pile section the data are the total (convex) circumscribed area and pe- rimeter, and the interior area and perimeter. Basically these numbers are assumed to re- present an exterior and an interior circler i.e. 'equivalent' circles if the pile section is of another shape.

Weight parameters : The total as well as the buoyant weight of the pile proper are required. The difference between these two values would show for instance whether the construction had any empty watertight com- partments.

Also the unit weight of water, and the atmospheric pressure expressed in the chosen unit system are required if any consistent unit system Is to be allowed, or if the analysis of centrifuge model tests is of interest.
Towed Ocean Bottom Instrument TOBI: A New Deep-Towed Platform for Side-Scan Sonar and Other Geophysical Surveys
Authors: Huggett Q.J. , Millard N.W.
Published: October 2008

TOBI is a new deep-towed geophysical surveying vehicle (figure 1) developed at the Institute of Oceanographic Sciences, Deacon Laboratory, U.K. Its standard instruments include: 31 kHz side-scan sonar (6 km swathe); a 7kHz high-resolution sub-bottom profiler (>50 metres penetration); a narrow beam, 1-20kHz scatterometer; and a high quality triaxial fluxgate magnetometer. It can operate in water depths between 200 and 6000 metres, and is towed from a steel armoured coaxial cable.

Since its completion in 1989, TOBI has completed almost 3000km of survey lines in water depths from 1500-6000 metres. These surveys were conducted from both British and American ships, in winds up to gale-force! TOBI images revealed targets ranging from subtle sedimentary textures to ship wrecks in 5km water depth.

Introduction.

Since 1965, when Scripps Institution of Oceanography built the world's first deeptowed system, a variety of these devices have been developed across the world 1. The basic requirement common to all of them was to be able to generate relatively high resolution images of the seafloor in a swath between 500 and 6000 metres wide. The reason for this is because there is a large leap in scale between surface-towed side-scan sonar systems and seafloor photography. This can prevent the engineer and scientist from either interpreting an image or mapping a sufficient area of seafloor. It was also recognised that having got an instrument to the deep ocean floor it would be cost effective to make more than one measurement.

The variation in swath width of deeptowed side-scan sonar systems is roughly dependant upon the frequency of the sound used. So the SAR system developed in France achieves a swath of 1.2 km at a frequency of 180 kHz, whereas the Towed Ocean Bottom Instrument (TOBI) described here achieves 6 km at 31 kHz.

When these systems were developed they were usually compared only by resolution and swath width. Recent results using a variety of side-scan sonar systems operating from 6.5 kHz to 31 kHz indicate that at these relatively low frequencies, acoustic energy penetrates sedimented seafloors z. So the images they produce are not of the sedimentiwater interface but a sum of the scattering strength of the upper few metres or centimetres of sediment. Therefore deep-towed systems must be assessed not only according to their resolution and range, but also by their ability to penetrate the sediment surface.

Acoustic penetration increases as frequency decreases, so TOBI (which uses a low frequency compared to other deep-towed systems) achieves the greatest penetration This property is of great importance where the target of interest to the engineer and scientist (e.g. manganese nodules or archeological remains) may be buried by a thin veneer of sediment. Recent results indicate that TOBI side-scan sonar may penetrate more than 25 cm into the sediment z. This effectively removes the masking effect of holocene sediments which are draped over many deep ocean seafloors.
Slope Angle Studies From Multibeam Sonar Data on Three Seamounts in Central Indian Basin
Authors: Kodagali V.N.
Published: October 2008

Slope angles are powerful morphometric tools. Slope angle studies in manganese nodule areas using the Multi Beam Sonar (MBS) data is useful to the mining geologist. A technique to convert depth grid generated from MBS data to slope angle values data is presented here. The slope angle grid can be used to create the slope angle map. Morphology of three seamounts from Central Indian Basin and the slope angle data on them are described. The seamounts are of the heights 1000-1200 m and occupy area up to 300 sq kms. The maximum slope angle around the seamounts is 38° with average being 10°. Over 80% of the area around the seamounts will be unmineable because of higher slope angles.

Introduction

Study of slopes and surface processes has been integral part of the geomorphological studies since the second World War. Slopes provide a basis on which by successive combination into larger units, general geomorphology of an area can be reconstructed. It is an important aspect in establishing relationship between geomorphology and other factors of environment. Just as the study of slopes forms a basis for geomorphological study on land, it can also be effectively carried out on seafloor data. Submarine geomorphology is challenging because of inability to observe things first hand 1 " However, slope angle studies on seafloor data have evoked considerable interest in the last decade. 2, 3,4,. Slope angle maps along with accurate depth contour map are essential for deep sea mining geologist to evaluate the resources and to eliminate unfavorable areas for mining. The path of the mine head has to be predetermined for which a detailed bathymetric and slope angle map of the area is a prerequisite. This study describes the technique for developing slope angle maps from the Multi beam sonar data.

Slope Angle Grid Generation

With the advent of multibeam system, the quality and the coverage of seafloor area have increased many fold. To generate a depth contour map from multibeam sonar data, the data from different survey lines is merged and a combined grid of depth values is generated. The technique developed for creating a slope angle grid from the depth values grid from HYDROSWEEP system Multibeam swath bathymetric system manufactured by M/s Krupp Atlas Elektronik, Germany (See references5,6 for technical details of the equipment) is briefly described here. The slope angle grid generated from this program can be used for preparing a slope angle map of area or slope profile across the area. The program is developed on EPR 1300 computer but with necessary modifications, it can be used on any computer. The program can also be adopted for land altitude data to create slope angle grids7
J-Tube Design for Flexible Umbilicals
Authors: Ronalds B.F.
Published: October 2008

The design of J-tubes with one or more bends under functional loads is dictated by a single force TL, the cable tension at the bottom of the J-tube. This facilitates the analysis of J-tubes using standard beam theory or, for complex shapes, a simple computer model. J-tubes experience both pull-in and pull-out loads in practice, and the latter govern J-tube design because the force TLis maximized.

1. INTRODUCTION

Flexible umbilicals comprising power, signal and fluid lines have found increasing use offshore in the control of satellite wells and subsea isolation valves. They are frequently brought into Topsides through steel J-tubes pre-installed in the jacket. Previous papers [1] have predicted pull-in loads for single bend J-tubes, but addressed the installation of a steel flowline rather than a flexible umbilical. The load required to pull an umbilical through a multiple bend J-tube is appraised in the present work; however, the stress analysis of the J-tube itself is the primary concern. A design method is developed, critical loadings other than pull-in are identified, and an optimum J-tube support configuration is highlighted. Throughout, it is assumed that the umbilical behaves essentially as a cable. A limiting flexural stiffness for the umbilical, beyond which the approach is not applicable, is estimated.

2. J-TUBE OPERATIONS

J-tubes are subject to both pull-in and pull-out loads, as indicated in Fig. 1.

The primary function of the J-tube is to enable the umbilical to be installed by pulling it up from seabed through the J-tube. This is performed using a winch located above the J-tube, which draws a cable attached to the nose of the umbilical.

Prior to installing the umbilical, the interior of the J-tube is generally protected by a diaphragm or plug at each end. 'l'& prevents free inflow of water into the J-tube and retards corrosion. Depending on its design, the lower seal can be removed by pulling outward, or inward through the J-tube.

One form of proprietary rubber diaphragm is shown in Fig. 2. During fabrication, a messenger line is passed through the J-tube and attached to the diaphragm. In-situ, the umbilical can be connected to outer side of the diaphragm just prior to pull-in. Winching in the messenger line from Topsides first breaks the diaphragm, and then pulls in the umbilical.

Umbilical installation methods vary, depending on the Operator. Another commonly used method involves the J-tube messenger line being pulled out of the J-tube by a winch on the lay vessel. The cable is then connected to the umbilical nose on the vessel deck to enable umbilical pull-in.

A defective umbilical would be removed by pulling it out of the bottom of the J-tube. Additionally, the umbilical maybe pulled out in-service due to accidental snagging from anchors or trawling.

To summarize, the following operations should be addressed in J-tube design:umbilical pull-inbottom seal pull-in/pull-outumbilical/cable pull-out
Flanged Coupling Design for the Snorre TLP Risers
Authors: Sele A.B. , Kilebu Magne
Published: October 2008

The flanged couplings adopted for the "Snorre" TLP risers are of a new and optimised configuration. The weight is comparable to that of a threaded coupling. So ia also the fatigue strength. The ultimate strength is equal to that of the tubular cross section of the riser joint. Make up and break out can be achieved rapidly and highly accurately with small and compact tools. In comparison threaded couplings of large diameters in particular require Iarge and cumbersome torque tools which achieve. a far lass precise prestress. It is believed that flanged couplings may provide the more optimal solution in many similar applications.

INTRODUCTION

The "Snorre" Tension Leg Platform stands in 320 meter water depth and is located in the Norwegian sector of the North Sea. It is operated by Saga Petroleum as. The design provides for 44 production risers of 9 5/S" diameter. There will also be an oil export riser of 20" diameter and a gas export riser of 10 3/4" diameter. Each riser string consists of 17 joints which are 51? long. Flangad couplings have bean provided for the couplings of the production risers in the splash zone as well as for the oil and gas export risers

The splash zone type couplings are provided in the most heavily loaded sections of the risers. The design loads are given in table 1. For the moat critical ultimate load combination the gross tubular cross section of the joint including the corrosion allowance is fully utilized. The flanges do as a consequence have an ultimate capacity in excess of that of the tubular cross section. The tubular cross section is also highly utilised in fatigue. As a consequence forged upset ends have been provided to accommodate the girth welds on the production risers and the gas export riser. On the oil export riser there are flush ends.

The compact flange concept which was adopted has also been used on shore in process pipework. In order to adapt this design concept to accommodate the design requirements laid down for the "Snorre" TLP, extensive non linear finite element analysis was performed. The general purpose non Iinaar finite element programme "Solvia" /1 / was used for this purpose.("Solvia" was previously known as "Adina".) The analytical results obtained ware verified with a comprehensive programme of full scale prototype tests which are described in more detail below.

DESCRIPTION OF FLANGES

Drawings of the flange coupling for the production riser splash zone type joints are shown in figure. The flange coupling for the gas export riser is of an identical configuration. Drawings of the oil export riser coupling are shown in figure 2. To avoid special transition joints splash zone couplings and standard couplings are of an identical design. The flange faces are carefully profiled to give the desired stress distribution after prestressing. This is described in more detail in the relevant sectional below..
Composite Riser Tubes: Defect Tolerance Assessment and Nondestructive Testing
Authors: Sparks C.P. , Odru P. , Metivaud Guy , Le Floc'h Christian
Published: October 2008

The work presented in this paper was carried out as part of a Joint Industry Program to qualify composite tubes for use as TLP production/injection risers. The program included the study of the influence of different kinds of damage on tube performance and fatigue life, the assessment of NDT methods for detecting damage and its evolution, as well as ways of predicting the ultimate performance of severely fatigue tested tubes. The following oil companies supported the program: Agip, Chevron, Conoco, Elf Aquitaine, Shell IPM, Statoil.

BACKGROUND

Initial Development

The Institut Francais du Petrole (IFP) and Aerospatiale have been developing high performance composite tubes for oil industry applications for a number of years.

Initial work concentrated on exploring the possibilities of different fibers and on finding technical solutions for details such as the tube end piece connection and internal/external liners for assuring pressure tightness. A large number of small diameter tubes were then tested in tension, pressure, bending, fatigue, ageing and abrasion.

This preliminary work led to a design consisting of a filament wound tube with a hybrid structure, comprising circumferential layers and longitudinal layers (see Fig.1), reinforced with glass fibers and carbon fibers respectively, set in an epoxy resin matrix. The end piece design (see Fig.2) consisted of a conical steel insert, fitted with steel shell pieces, to which the composite was bonded.

There are many possible applications of composite materials to the offshore oil industry (see ref.1). The initial one considered by IFP/ Aerospatiale was 4" J.D. Kill & Choke lines of drilling risers. Several such tubes were built and tested and in 1983 six 15 m long tubes were successfully tested on a drilling riser in the North Sea. Composite TLP Risers

Since 1985 IFP/ Aerospatiale have concentrated on the development of larger diameter (9r) composite tubes for applications to production/injection risers of deepwater TLPs.

Work on the composite risers of the PLTB 1000 project (see ref.2) showed the potential benefits that could be gained from the principal characteristics of composites, which included high strength and low weight, as well as their elasticity and their excellent behavior in fatigue and corrosion. These promised to allow large reductions in riser top tensions and also the elimination of tensioners, leading to economic benefits.

In 1985 IFP mounted a joint industry program (JIP No.1), supported by seven major oil companies, with the object of building samples of composite risers for TLPs and subjecting them to thorough mechanical testing. The tubes were 9" ID, with a hybrid wall structure made up of glass fiber reinforced circumferential layers (total thickness 9.57mm) and carbon fiber reinforced longitudinal layers (7.28mm thick). A cross-section of the tube is shown on Fig.3, where the layered structure of the wall can be clearly seen.