bluuebunny/crossref_metadata_2025 huggingface dataset:
Jacket Performance due to Foundation-Degraded Response
Authors: Mirza U.A. , Maclaren D.J.
Published: October 2008

This paper is concerned with the prediction of the ultimate capacity of piles driven into clays to support offshore production and drill i ng facil it i es. Such pil es are generally long and flexible and oftenarranged in clusters around the jacket corners. Pile des i gn methodology is progressively moving towards pile capacity methods that consider explicitly pile length effects and soil strain softening on skin friction.

The paper presents a method for evaluating the residual skin friction from basic properties for clay soils based on an interpretation of data from North Sea sites. Interactive jacket/foundation analyses were made to demonstrate the effects of variation in the pile loaddeflection stiffnesses on the foundation reactions.

INTRODUCTION

Pile axial capacity calculations for offshore platforms are commonly based on API RP2A method. The ultimate capacity is calculated as the sum of skin friction and end bearing components. This paper is concerned wi th sk i n fri ct i on and how its degradation with axial displacement affects pile capacity and load-displacement behaviour.

Prior to 1987, calculation of pile skin iriction in the North Seaclays used to be accomplished on the basis of Paragraph 2 of API RP2A25wherein the adhesion factor alpha is taken to depend on the value of the undrained shear strength only. The introduction of the method by Randolph and Murph/, based on the ratio of undrained shear strength to effective overburden pressure into API RP2A (1987)2 has meant that a large increase in capacity is calculated for long piles driven into normally consolidated clays, if pile lengtheffects are ignored. An increase in capacity by some 75% is predicted for some clay sites in the deeper waters of the North Sea. In reality, pil e 1ength and fl exi bil ity effects will tend to reduce capacities thus calculated.

One way of mode" ing such effects is to consider the degradation of skin friction as the pile is axially displaced relative to the soil.

In this paper a method for determining degraded friction has been developed using North Sea soils data. This method has been applied to various sites and the results described in the example es presented. Interactive jacket/foundation analyses were made to demonstrate the effects of degradedfriction on pile behavior under a range of loads. Also, results of sensitivity analyses are reported for a range of axial and lateral load deflection stiffnesses.

PILE DESIGN CONSIPERATIONS

Randolph3 has shown parametrically the importance of considering post-peak skin friction reduction and pile flexibility in pile capacity calculations. It may be noted that in Figure 2 of Randolph and Murphy's paper, their design alpha relationship is well above the pile load test points for strength ratios of 0.23 to 0.29. These points belong to piles with length of between 30 and 75m (discounting the data for redriven piles).
Critique of Offshore Pipelay Criteria and Its Effect on Pipeline Design
Authors: Sriskandarajah Thurairajah , Mahendran I.K.
Published: October 2008

The pipelay criteria currently used for pipeline design is based mainly on submarine static pipelay analysis results. The criteria recommended in the codes and by operators are sometimes more stringent than necessary and affect the layability of the pipeline, and the capability of pipelay barges. This problem is illustrated herein using both static and dynamic analyses of a typical pipelay operation. The analysis show that for large diameter pipelines, the design is restricted to the maximum layable submerged weight to satisfy the pipelay criteria. In order to achieve this, the pipeline may need trenching to provide additional stability, or require a higher awlied tension, over and above the installed tension capacity of the pipelay barge. It is shown here that this can lead to an increase in the project cost and schedules. The results presented herein show that by Modifying the arrrent pipelay criteria, it is possible to lay heavier pipelines, thus i..rrq;>roving the cost effectiveness of a project. An example is presented illustrating the effect of pipelay criteria on the design of a large diameter pipeline and show that further cost savings could be made on pipeline trenching and pipelay barge modification required.

INTRODUCTION

The design of an offshore large diameter pipeline is dependant to a large extent on the availability of pipelay barges to install the pipeline. The pipe layability, using the chosen barge, will Impact on the maximum design concrete coating at a particular water depth and thus provide an upper bound to the amount of negative buoyancy available to satisfy on-bottam stability requirements. The negative buoyancy requirement for a pipeline is dependant on the pipe size, hydrodynamic forces and the pipe/soil interaction characteristics. This is an area whidl has been the subject of considerable research activity in the recent past. As a result, there are a number of computer programs developed to help the designer to achieve a submerged weight requirement for the pipeline to satisfy the various stability criteria.

In most cases, the resultant submerged weight of the pipeline can be laid by a pipelay barge and the pipeline will be stable on the seabed during its lifetime. However, in sane cases, the resultant submerged weight of the pipeline is too heavy an:i hence cannot be installed by the pipelay barge to satisfy the pipelay criteria. To overcome this problem, it is necessary to either trench the pipeline and reduce the negative bouyancy requirement, thus Improving the layability of the pipeline, or to increase the capability of the pipelay barge tension/overbend support system so that a heavier pipeline can be installed. The first option depends on the suitability of the seabed for trenching, e.g. sandy or clay. If the seabed consists of rock or boulders, this may not be a viable option. In this case, the pipeline has to be designed to be stable on the seabed, with the pipelay barges being modified to facilitate installation.
Offshore Hydrocarbon Surveys
Authors: Behrman R.G. , Land J.P.
Published: October 2008

Over 50 years experience with adsorbed hydrocarbon soil surveys carefully correlated with geological and geophysical information has proved that discovery rates can be as high as 84%. Over the same period the API reports show that new field success rates were never over 19%.

This paper discuses the results of hydrocarbon surveys conducted in 1973. 3,600,000 acres of the Gulf of Mexico off Texas and Louisiana. The surveys were made or the purpose of evaluating blocks to be offered for sale at various times during those years.

The sampling device used was a piston type corer fitted with a six foot barrel three inches in diameter. 500 gram samples were taken from the bottom part of each core for adsorbed hydrocarbon determination of methane, ethane+ and pentane values. Bottom water samples were taken for determining their methane content and sediment samples for their interstitial content of methane.

From the interpretation of these data, 89 features were designated prospective. In the ensuing 16 years 43 of the features were drilled and the result was the discovery of 38 new fields.

During that same period 160 dry holes were drilled within the various survey areas but outside the boundaries of the interpreted prospective features.

The purpose of this paper is not just to demonstrate the validity of the proper procedures and applications of surface geochemical surveys but, more importantly, the greater success and economy to be had through true multidiscipline exploration.

INTRODUCTION

There is now a growing recognition of the merits of the surface geochemical survey method and its ability to define local concentrations of light hydrocarbons in the near-surface formations is recognizable patterns. This greater acceptance is due largely to two things:The increased useage of surface hydrocarbon surveys in the offshore, especially in the Gulf of Mexico, and the fact that the surveys could be evaluated soon after completion. With a high percentage of the hydrocarbon anomalies confirmed by drilling, explorationists were more prone to accepting a basic premise that there is a vertical migration or, rather, microseepage of light hydrocarbons from reservoirs at depth.Carbon isotope studies of the samples show that near-surface methane sampled above reservoirs is almost the same as that in the reservoir and is different from biologic methane (Horvitz).

A high percentage of the world's oil production was first noted due to surface seeps. The Drake well drilled in Pennsylvania in 1859 is an example. In the offshore we see gases bubbling from the bottom sediments. Surface seeps are increasingly fewer and less visible but the search continues and successtully. via the surface geochemical method. nethod with sophisticated instrumentation and procedures measuring hydrocarbon content in parts per billion by weight.
In-Service NDT Inspection Equipment for the Snorre TLP Tethers
Authors: Flogeland Svein , Smith B.J. , Gobbo Gianfranco
Published: October 2008

Equipment for in-service NDT inspection of the Snorre TLP tethers has been developed. This paper describes the design basis and main functional requirements as set forth by the operator Saga Petroleum a.s., and describes the main challenges of the development and how these have been met through a systematic programme of testing and design.

INTRODUCTION

The Snorre field, operated by Saga Petroleum a.s., is heated 150 km west of Flora, Norway and is developed by means of a tension leg platform and subsea installations. The waterdepthis310 mat the platform location.

The Snorre TLP tether system is based on a through column installation method with tether string tie-off at a mooring flat above water level. There is a total of 16 tether strings, 4 in each corner of the TLP. Typical external diameter is 32 inches and wall thickness is 1.5 inches. Reference is made to figure 1.

The tether string is composed of an anchor latch for connection to the seabed foundation, a number of tether elements to provide the major length of the tether string, a cross load bearing to transfer horizontal forces from the tether to the platform hull and a top tie-off assembly at the top to adjust the tether string length and force. All these components have threaded coupling-parts to facilitate assembly of the tether string during platform installation. The tether couplings are welded to the tether component pipe or shaft and there are 40 such circumferential girth welds in each tether string. /ref. 1/.

To provide in-service inspection of the tether girth welds, a dedieated tether in-service NDT-inspection equipment, based on ultrasonic inspection techniques, has been developed. The purchase order for the design, fabrication and testing of the inspection equipment was awarded by Saga Petroleum as. to Veritec in September 1990 with scheduled delivery in April 1992. Development of the system has been performed in close cooperation with 2 major subcontractors, i.e. APS Harwell of U.K. (ultrasound system) and Tecnomare SpA of Italy (inspection vehicle).

Main challenges in the project were development of an ultrasonic system which could detect and size defects as specified by the client with sufficient reliability, positioning accuracy of the inspection vehicle and ultrasound probe arrays, ultrasound couplant supply, fully automated operation within tight time constraints and fast data analysis with operator-friendly interpretation and presentation of results.

DESIGN BASIS

The design basis for the in-service NDT inspection equipment was established through several studies in which the effect of possible defects in the tethers was evaluated. Probabilistic crack growth studies were instrumental in this evaluation as was an assessment of crack detection capabilities of latest generation ultrasound technology /ref. 2/.

Since in-service NDT inspection equipment as required for the Snorre tethers has not been built before, the equipment specification describes only functional requirements and not design solutions.
Safety Consideration of TLP on Earthquake Wave Propagated Through Seawater
Authors: Kobayashi Hiroshi , Sakuta Masaaki , Okamoto Kyoichi , Hirakawa Seiichi
Published: October 2008

Seaquake is caused by propagation of the seismic motion of seabed through seawater. Althou h aseismatic design has been providing ap licab5 e marine structures for earthquake zones: e1f?ects of seaquake maybe one of items to be taken mto further consideration about the safety of TLP (Tension Leg Platform). Hydrodynamic ressure caused by sea uake is analyzed and its ef ?ects to a hull of T1P is investigated.

Effects of seaquake de end on the water depth, seismic intensity and prei ominant period and size of seabed in vibration. Seaquake may impose impact load on a hull and is advised to be taken into consideration of the safety of TLP.

INTRODUCTION

Deep sea is one of new frontiers for oil production, Emerged aa measures to cope with this new frontier, TLP has been performin the same functions of oil rigs effectively as those of conventional jacket-type platforms done for shallow sea.

Namely, TLP has been applied ractically to offshore oil reduction at the Hutton Fielc?in North Sea in 1984 anf at the Green Canyon Field in the Gulf of Mexico in 1989, which are followed by their counterparts under construction at the Snorre Field and the Heidrun Field in North Sea. TIJ? is now considered to be a promising structure to conquer the new frontier of deep sea.

The Japan Ocean Industries Association (JOIA) has organized a technical committee of TLP of a new concept which can be installed in offshore oil fields of earthquake zones. The committee has worked out a concept of a sde and economical TLP for deep sea of earthquake zones and performed research and development on fundamental techniques sustaining the concept.

PROTOTYPE STRUCTURE

The outline of the prototype TLP prototype which the JOIA committie has stuchedis shown in Fi .1. A steel hull with a mounted deck is moored with four sets of tendons stretched downward in tension to a template of hybrid structure.

The steel hull is composed of a frame deck structure, columns and pontoons. Six columns with circular cross section support a pair of longitudinal and transverse main girders of the deck and four corner columns are anchored with tendons to a template placed on the seabed.

The total of 16 tendons made of steel pi es with the diameter of 609.6mm are provided with Four tendons per a corner. The template is a avity-type caisson of steel-concrete hybrid structure %a! ving a square cross section with rounded corners for scour protection.

This TLP is applicable for offshore oil field with flat seabed having proper bearing capacity and water depth equal to or more than 500m. Environmentalconditions used for design and construction plan of the TLP areas summarized in Table-1.

RESEARCH AND DEVELOPMENT

To co e with effects of seismic motion for the seabed toa Tb installed in earthquake zane is taken into consideration for a transmitting path of seismicmotion from seabed, template, tendons to hull, aseismatic design of its structure.
Comparison of Analysis and Full-Scale Testing of Anti-Recoil System for Emergency Disconnect of Deepwater Riser
Authors: Young R.D. , Hock C.J. , Karlsen Geir , Albert J.W.
Published: October 2008

This paper describes the verification of a procedure for analyzing the emergency disconnect of deepwater drilling risers. The procedure was used to design an anti-recoil system for Sonat's Discoverer 534 drillship. The purpose of this system is to provide control of the riser's ascent velocity and hence to limit its impact with the diverter housing. The system was tested during an actual disconnect in 3700 feet of water. This test was full scale and instrumented to provide riser displacement and pressure drop across the anti-recoil valves in some of the tensioners. The data was used to verify the analysis and design procedure. This procedure is briefly discussed herein, but a full discussion is available in a companion paper (1).

INTRODUCTION

In late 1989, BP Exploration initiated plans for upgrading Sonat's Discoverer 534 Drillship to a 6000 ft operating water depth (2). Several primary systems were installed or modified. One of these was the riser tensioner system to which a riser anti-recoil system was added. The purpose of this system is to avoid accelerating the riser into the diverter and substructure following an emergency disconnect. The anti-recoil system and associated procedures were designed by computer analysis of the riser/tensioner system (1,3). The computer program used is called RISTEN and is owned by Shell Development Company.

THE FULL SCALE TESTS

Since the anti-recoil system was designed by computer simulation {jJ everyone agreed that a full scale disconnect test was needed to verify the computer analysis. The first opportunity for testing turned out to be the first well after the D534 upgrade was complete. This was in 3700 feet of water in the Gulf of Mexico.

The tests consisted of a disconnect test and two bump tests. The two bump tests consisted of pulling the riser up from its post-disconnect resting position of 4-5 feet short of full TJ (telescoping joint) collapse. Refer to "Bump Tests" portion of this paper for more on these. Test instrumentation included the following:Video cameras located at strategic locations,Pressure transducers located on each side of the anti-recoil valves (see Fig. 1) of 3 selected tensioners,The rig's magnetic slider/tensioner position indicator located on one of the three selected tensioners, andTwo accelerometers located near the top of the TJ's outer barrel.

The pressure transducers were installed on each side of anti-recoil valves (see Fig. 1) for tensioners 2B (#2 Bow), 4A (#4 Aft), and 5B (#5 Bow). These were Precise Model 555 strain gage pressure transducers.

The magnetic slider/tensioner position indicator was pre-existing equipment on the D534. The electrical signal sees a unit step change each time the slider reaches a different monitored point. The monitored points are spaced 1 inch apart, which causes a unit stepped voltage output signal at slow speeds and high frequency pulses at higher speeds.
A Marine Riser With Internal Flow-Induced Vibration
Authors: Chen B.C.M.
Published: October 2008

The internal fluid dynamic and other conventional forces are described completely in the governing equation of the lateral vibration of a marine riser. The current scope of work is to determine the natural frequency and the mode shape of an undamped riser. With proper tension expressions, the equation is applicable to the neutrally, negatively or positively buoyant riser system.

From the fluid-elastic vibration point of view, the fluid dynamic force produces the effect which is opposite to that of the riser tension. The force decreases the natural frequency and may create a dynamic instability as the fluid flow velocity approaches the critical, buckling or significant values.

Introduction

A marine riser is a conductor which links the floating vessel on the sea surface and the manifold on the sea bottom. The depth of the sea can be from several hundred to a couple thousand feet. The riser can be a single rigid pipeline for the drilling riser system, or a bundle of flowlines which are assembled as an integral unit for the production riser system. The riser system can be installed for the tension leg platform (TLP), floating production and storage unit (FPSU).

To avoid the collapse and buckle of a riser by its own weight and to reduce the excess load on the manifold in the deep sea, a constant top tension is applied. Buoyant material is strapped around the riser at intervals to provide an additional buoyancy and to reduce the required top tension. The additional buoys make the riser neutrally, negatively or positively buoyant depending on the applications. These are some of the features of the deep sea marine riser. An applied mechanics for marine riser systems has been provided by Morgan (l).

The drilling or the production fluid flows internally from one end to the other, inside the conductor along the transversely deflected riser loaded by the environmental forces. The fluidparticles of the internal flow experience the dynamic force of centrifugal and Coriolis accelerations as they travel inside the curved path along the deflected riser. The fluid dynamic force exerts periodically against the interior wall of the conductor along the riser. The force is integrated into the vibration of the riser. Or worse yet, the vibration may be locked-in by that of vortex shedding and together they resonate. This, in turn, will fail the riser system prematurely. For the general knowledge of the centrifugal and Coriolis accelerations, readers may refer to any text book of engineering mechanics or Hibbeler (2).

An aerodynamic force induced vibration on a horizontal pipeline supported at intervals above ground, has been observed and analyzed by Housner (3). He has concluded that the internal fluid velocity causes a dynamic coupling of the simple modes of vibration of the pipeline. At low fluid velocities there is negligible effect upon the vibration of the pipeline, and at a certain high critical velocity the internal fluid flow causes a dynamic instability. The fluid velocity contributes the centrifugal and Coriolis accelerations in the deflected pipeline.
Fatigue Life Enhancement of Semisubmersible Rigs
Authors: Chaudhury G.K.
Published: October 2008

Details of engineering techniques of cost-effective, safe and reliable means of improving structural fatigue lives of spaceframe semisubmersible drilling rigs have been presented. Furtner advancement to fatigue life calculations has been validated and proposed. An integrated procedure for rig upgrading has been outlined. Different ways of achieving extended fatigue life and the attending cost impact has been examined.

INTRODUCTION

Market rates of semisubmersible drilling rigs and the cost of building new rigs do not complement each other. This present situation is expected to continue for significant time. Cost estimates have shown that current day rates can justify the investments required to upgrade older rigs to present day standards, both in terms of operational and regulatory requirements. Consequently, rig owners are seriously thinking about the engineering feasibility of such upgrading and if possibly what would be the engineering involvment, costs, safety, operational reliability and structural integrity.

An in-depth study/investigation was undertaken which has carefully considered the followings points:Past fatigue performances of all key joints.Regulations today and future trends.Recent research into fatigue strength improvements.Advances into fatigue calculation methods.

The results were integrated into a systematic engineering solution procedure which yields an inexpensive, safe and reliable way of extending and enhancing the fatigue lives of the older rigs.

ECONOMIC CONSIDERATION

The demand for semisubmersible drilling rigs has grown steadily and cautiously from its lowest level of June 1987. Associated day rates have moved up proportionately but still lagging behind as the curve for supply still exceeds tile market demand for these rigs (Fig 1). Nevertheless, the supply of rigs is reducing gradually due to planned retirement of older rigs and a virtual stop in the new buildings.

Assuming that demand and supply curves continue in the same way as have been so far these curves will not converge till significantly in the future. This will not warrant additional supply of right for several years. However, supply may need to be stabilized before and it is prudent to be prepared in advance. The day rate trend does not indicate any sharpe rise in the short term and consequently anticipated day rates in 2 to 3 years time will only be a fraction of what is required for new building of rigs to be economically viable.

Under the circumstances, therefore, supply of rigs will not be increased. Supply can be stabilized by revitalizing the older rigs ready to retire. This means engineering solutions must be found to be able to upgrade the older rigs up to today's regulatory standards and customer's specifications at a cost that can be supported by present day rates.

UPGRADING REQUIREMENT

First we need to establish what kind of upgrading/enhancement is required to these older rigs which will satisfy present day demands for efficient, safe and reliable drilling operations. This approach can be subdivided into two categories.
In-Situ Post-Weld Heat Treatment of Wet Welds
Authors: Szelagowski Peter , Ibarra Santiago , Ohliger Annegret , dos Santos J-F.
Published: October 2008

1.0 Introduction

There is a substantial interest in implementing wet welding for structural repairs of offshore installations. Some of the restrictions to its use are heat affected zone (HAZ) hardening and cracking, and the inability to produce wet welds that meet the bend test requirements of a surface weld. Restrictions to the application of wet welding are even more sever in the North Sea where high strength, high carbon equivalent structural steels are used. A reduction of the diffusible H2 contents of wet welded joints (i.e. lower risk of H2 induced cracking) would certainly lead to a re-evaluation of the process regarding its practical application, especially considering high carbon equivalent steels. This is more so in face of the acceptable mechanical properties and low defect rates achievable with some of the electrodes presently available.

Such desirable reduction in the weldments H2 content could be achieved through an "in-situ" (underwater) post weld heat treatment (PWHI). In order to evaluate the feasilibllity of such heat treatment method a series of tests has been carried out in which bead-on-plate welds have been deposited on high carbon equivalent base plates and then submitted to different "in-situ" heat treatment procedures. This report presents the results of these preliminary investigations.

2.0 Theoretical Background

Due to the fast cooling rates and the high hydrogen content, characteristic of weldments produced in wet environment, hardening and cold cracking in the HAZ and weld metal are possible, especially in the case of high carbon equivalent steels (CE > 0,40 %) /1/.

Postweld heating methods have been investigated in order to improve the mechanical properties of underwater welds 12,31. One way to prevent cold cracking in underwater welds is to facilitate the diffusion of atomic hydrogen by heat treating immediately after welding. Suga /2,3/ investigated the effect of post-weld heat treatment on the occurrence of cracks and on the evolution process of hydrogen out of the welds using beadon-plate runs (13Omm in length) deposited underwater. After removing the slag, the test plates were immersed into an isothermal bath within 60s after completion of the welding. The test plates were kept in the bath for J)l'eset times, then cooled in water and left in air at room temperature. Suga /2,3/ obselVed the occurrence of under bead cracks in the HAZ of underwater welds within a period of about 5 min. after welding. His observations stated that under bead cracks as well as root cracks could be prevented by "in situ" PWHr above temperatures of 100 DC with appropriate holding times.

Similar results have been achieved by Ibarra et. al. /4/ using the multiple temper bead technique. This technique involves immediately placing a second pass over the previous one to soften the hardened HAZ and eliminate hydrogen. The experimental and practical results obtained indicated that this method was successful in assisting hydrogen diffusion out of the weldment /5/.
Clad Steel: An Engineering Option
Authors: Smith L.M.
Published: October 2008

Corrosion resistant alloy clad steel has been available in various forms for over 40 years and is being used increasingly in the oil and gas production industries. In the context of the specific requirements of this industrial sector, methods of manufacturing clad plate, pipe and fittings are given along with welding details and information on existing field applications of clad products.

1. INTRODUCTION

The use of corrosion resistant alloys (CRAs) for the control of corrosion in oil and gas systems has a number of benefits. Production systems constructed of correctly selected CRAs (based on appropriate laboratory testing or previous field experience in similar enVironments) will provide a safe, leak-free system for the full duration of a project. Whilst the inital capital expenditure often appears to be higher for a CRA system there are great savings to be made in reduced processing requirements through the safe handling of wet corrosive fluids. If well fluids can be transported to shore or to an existing platform without drying then the cost savings in equipment, weight andspace can be more than sufficient to cover the expense involved in the CRAs needed to handle the fluid from the well to the processing facility.

Additional savings can be made in operating costs since corrosion inhibitor injection is not required and inspection and maintenance costs are greatly reduced compared to a carbon steel production system (with or without internal organic linings). Thus if a life-time costing approach is taken CRAs can often be show to be an economic corrosion control option for oil and gas production systems.

Nevertheless, CRAs contain expensive alloying elements, particularly the more highly alloyed materials required for corrosive sour production systems. Clad steel is a composite product developed to provide effective and economic utilisation of expensive materials. The cladding layer which will be in contact with the corrosive fluids is made of the corrosion resistant alloy whilst the less expensive backing steel providesthe strength and toughness required to maintain the mechanical integrity. Because high strength backing steel can be utilised, wall thicknesses can be reduced relative to solid CRAs thus reducing fabrication time and costs.

The cost saving from using clad steel rather than solid CRA is particularly valid when the total thickness increases or when the cladding grade becomes more complex and hence expensive. An indication of the sort of savings which can be made is illustrated for integrally bonded clad plates in Figure 1. Clad steel plates have been utilised with great success in processing vessels, heat exchangers, tanks and a variety of material handling and storage facilities as well as for making longitudinally welded clad pipe. Clad steel has been available in various forms for more than 40 years and has been widely used in the chemical, oil refining and chemical transport industries and more recently in oil and gas production. Yet despite this there are still concerns regarding the use of clad steel..
First Emergency Shutdown Valve, Norwegian Sector
Authors: Eriksen Gunnar , Bondevik J.O. , Bergum Bernt
Published: October 2008

The Subsea Emergency Shut Down Valve (SESDV) was Installed in December 1991 as an Integrated part of the Oseberg Multiphase Transfer System (MTS), between the Oseberg Field Centre and the Oseberg C platform. This paper describes the concept evaluation, design philosophy, fabrication, testing and installation of the SESDV.

Due to the discovery of additional oil reserves which could be reached from the Oseberg C platform a phased development of the reserves was decided, As a consequence, a new safety evaluation of the C platform had to be performed. This concluded that in order to minimise consequential damages to people and platform in case of a fire at sea or a riser rupture situation, a SESDV should be Installed close to the platform.

INTRODUCTION

The Oseberg Field, is located in blocks 30/6 and 30/9 in the Norwegian Sector of the North Sea, was decided to be developed by Norsk Hydro and it's five partners. The first stage of the Oseberg Field Development was completed in December 1988, when the Oseberg Field Centre was put in operation. The second stage of the Oseberg Development was completed in September 1991, when the Oseberg C platform was put in operation after an offshore hook-up period of four and a half months. A multiphase pipeline (MTS) has been installed and is due to be on stream by March 1992. The lay-out of the Oseberg Field is shown in Fig. 1.

The MTS pipeline will transport unprocessed oil from the C platform over a distance of 15 km before being processed on the Oseberg Field Centre. Due to the corrosiveness of the fluid the design life time of the pipeline is 10 years.

With the conclusion of the platform-safety report in mind, two conceptual studies of SESDV was run in parallel, in summer 1990 in order to combine existing knowledge from Norwegian Sector with practical knowledge from the English Sector. With the results of the two studies, specifications were made. An EPC contract was awarded in February 1991 for delivery of the complete SESDV system by October 1991.

* The partners of Norsk Hydro Produksjon NS in the Oseberg development are: Den norske stats oljeselskap (STATOIL), Saga Petroleum NS, Elf Aquitaine Norge NS, Mobil Exploration Norway inc., Total Marine Norge NS.

PLATFORM SAFETY - SESDV LOCATION

In case of a riser rupture, the riser for the MTS with the valve at the seabed will be emptied at a much shorter time than used for closing the valve. Therefore it is the valve closure time more than the location that determines the amount of gas released, provided it is not located too far away from the platform along the pipeline. With the SESDVlocated 500m from the platform, the blowdown time is about 25 seconds (assuming immediate closure of the valve), or approximately the acceptable maximum valve closure time.
Lifeboat Launch Simulation and Its Application to Safety Assessment
Authors: Luo Yong , Trickey J.C. , James C.E. , Jack R.L.
Published: October 2008

The paper deals with the motion simulation of lifeboats launched from fixed or floating platforms and its application to collision risk assessment. The mathematical model of the Davit launch system is presented. By solving the motion differential equations, the three dimensional motion responses of the lifeboat and the platform are simulated in the time domain and the clearance between the lifeboat and platform structural members are monitored. Numerical examples are given and key parametric effects are investigated through deterministic and probabilistic analyses. It is demonstrated that the motion simulation combined with probabilistic analysis techniques can provide an effective tool for quantitative risk assessment of offshore emergency evacuations using lifeboats.

1. INTRODUCTION

During an emergency evacuation from offshore fixed or floating platforms, it is of vital importance that lifeboats can be successfully launched and disconnected from the platform. This is actually one of the recommendations made in Cullen's Report [1] into the Piper Alpha disaster which states: "Operators should be required by regulation to submit to the regulatory body for its acceptance an evacuation, escape and rescue analysis in respect of each of its installations".

Aimed at improving the understanding of thebehaviour of lifeboats during launch and assessing the risk involved due to possible collisions with platform structural members, the lifeboat launch operation is studied using response simulation techniques. The current study focuses on the traditional Davit launch of lifeboat system for TEMPSC (Totally Enclosed Motor Propelled Survival Craft) whereby the lifeboats are lowered vertically from winches on two cables (see Fig.1). It addressee the following main issues:Motion responses of lifeboats during descending from floating or fixed platformsLifeboat movements during turning and sailawayKey parameters and their effects on motionand risk of collisionProbabilistic analysis as a tool for safetyassessment

For lifeboats launched from floating structures Such as semisubmersible units, the lifeboat motion response caused by environmental loading and the platform motion is mathematically modelled. The motion equations are solved numerically to simulate the lifeboat and platform responses and monitor the occurrence of collision in the time domain. Impact velocity can be computed if collision occurs to determine the extent of damage.

Investigations of key parametric effects are carried out. The main parameters studied are the types of platforms, severity of environment, vertical descent speed, disconnection time and lifeboat heading. Useful results are obtained which will help the development of appropriate evacuation procedures.

It is also demonstrated in the paper thatprobabilistic techniques can be incorporated into the analysis to obtain a quantitative indicator of the risk level of lifeboat launch. The results canbe valuable for aseessing the adequacy of evacuation procedures using lifeboats.
Requalification of a Platform in Cook Inlet, Alaska
Authors: Bea R.G. , Landeis B.T. , Craig M.J.K.
Published: October 2008

This paper outlines and illustrates an engineering evaluation procedure for re-qualification of high consequence offshore platforms. The procedure is illustrated with application to a Cook Inlet patform that was damaged by a blowout. The anaPyses and evaluations documented in this paper indicate that the damage was successfully repaired, and that the structure in its repaired condition is fit for purpose.

INTRODUCTION

In 1985, a platform operated by Unocal (coowned by Marathon and Arco) located in Cook InIet, Alaska (Fig. 1), experienced a blowout which created a large crater encompassing three of its four legs (Fig 2.) The blowout serious y damaged the foundation (crater depth at Leg-1 was approximately 80-fi deep) and caused some damage to the superstructure.

The foundation was repaired by filling the crater with 100,000 cubic yards of gravel and by driving twelve 20-in diameter insert pies into the existing piles in Leg-1. Preliminary studies of the performance of the repaired platform when it was subjectedto lateral loadings from earthquakes and ice floes indicated that a more rigorous and detailedevaluation of the serviceability of the platform during extreme conditions was necessary [1,2].

BACKGROUND

The platform location is in upper Cook Inlet in a water depth (mean lower low water) of 125 ft. The maximum tidal range is approximately 30 ft.

The Inlet is covered with ice during the wintermonths. Strong tidal currents move ice up and down the Inlet twice a day. Ice thickness can range from 3 fi to in excess of 6 ft (rafted, Stamuki).

Cook Inlet is situated in one of the most active seismic zones in the world. Numerous majorearth shakes have occurred in this area including the 1964 Good Friday Prince William Sound earthquake (magnitude 8.5). In the last 65 years, 15 events of magnitudes greater than 6 have occurred in thisarea.

Subsurface soil conditions vary greatly and ran e from soft unconsolidated clays on the west sideoft i?e Inlet to boulder-covered extremely stiff clays in the middle and east side. In the upper Inlet the soil conditions generally can be classified as deep, firm alluvium.

The platform is a steel, tower-type platform that has four 17-ft diameter legs (Fig. 1). The toweris braced with horizontal and vertical X-bracing below water (Fig. 1? 3). The le s span the tidal zone (kept open to minimize ice loafing) and are joined at the deck level by 17-ft diameter horizontal beamtanks. The multi-level enclosed drilling and productiondecks are mounted on top of the beam tanks.

Each of the platform?s legs contain 12, 33-inand 26-in diameter two stage piles (Fig. 3). Inside the piles are well conductors (multiples strings of casing) that are cemented to the formation and the piles.

The soil conditions at the platform (Leg-1 profile, Fig. 4) consist of very strong stiff clays belowpenetrations of about 125 ft overlain b lower strength stiff clays and the gravel used to F111the blowout crater.
Design and Installation of the North Dauphin Island Platform
Authors: Beal D.D. , Allen J.D. , Datta B.N.
Published: October 2008

The shallow water of Mississippi Sound restricted the selection of structural concept to support a 70 mmscfd gas processing facility. The project team picked a structure type which could be floated over and set on pre-installed piling instead of the traditional lifted deck. This mode of installation provided for a competitively bid and economical installation since it used equipment which is commonly available at reasonable day rates.

Installation procedures for the 1400 ton deck insured a gradual controlled transfer of load from barge to piling. Shock cells in the legs, compressible supports on the barge, sand cans in the legs and on the barge, and a digital read-out of loads from strain gages on the legs allowed gradual transfer of deck load from barge to pile. Testing of the shock cells and a sand can before actual use insured proper operation offshore.

INTRODUCTION

The North Dauphin Island field consists of about nine square miles in Mississippi Sound just north of Dauphin Island, a barrier island off the coast of Alabama. Six satellite wells produce gas from the Shallow Miocene formation to a central gathering facility, the North Dauphin Island platform, in Alabama state tract 73. The platform houses sweet gas processing equipment including two 2200 H.P. reciprocating compressors. No production wells are located on the platform.

The environment of Mississippi Sound made the design and installation of the North Dauphin Island platform unique in comparison with the vast majority of Gulf of Mexico facilities. The platform site, shown in Fig. 1, is 2400 feet south of the Intracoastal waterway and a half mile north of Dauphin Island. The water at the site is only 11 feet deep and water depths in the field are a maximum of about 13 feet. Only one heavy lift barge was available in the Gulf of Mexico which could lift a 1400 ton deck in the shallow water, and designing the structure to be totally dependent on this barge couldhave burdened the project with some significant constraints.

The regulatory environment also made this project unique. At the time of design, the state of Alabama required that oil and gas operators discharge nothing into state waters during construction and operation offacilities.

CONCEPTUAL DESIGN

The unique site conditions offered designers several structural alternatives from which to choose. While there was a single heavy lift barge capable of working theshallow water, the owner decided to avoid the complications which would accompany dependency on a single piece of equipment. Other viable alternatives were established and compared in a brief technical and economic evaluation. Environmental and aesthetic aspects of the alternatives were also examined. The structural alternatives which were considered are listed below. In all alternatives the deck would be outfitted with process equipment prior to offshore installation.
Installation of the South Pass 52 Platform
Authors: Allen J.D. , Beal D.O. , Kessler K.J. , Mukerji Paddy
Published: October 2008

Installation of the drilling and gas production platform for South Pass 52 required extensive planning and careful consideration of risks brought about by the tripod configuration, economic limitations on exploiting a marginal prospect, soft soils, and potentially significant currents. The jacket, 548 feet long and 2700 tons, relatively light for the water depth, was lifted from the barge at sea. Five foot deep skirts on the mud mats helped mobilize adequate bearing capacity and minimized mat size. Carefully selected ballasting, attention to currents and weather forecasts, and a short exposure time partially compensated for the limited resistance to overturning of the jacket before piles were driven. The jacket made the first use of a new type of pile gripper, shop tested before deployment, which could be used to grip stabbed or partially driven piles for levelling the jacket and minimizing jacket motion during grout set-up. Performance of the plans and systems for installation was generally satisfactory. The risks accepted for the installation were believed to be near the economic optimum. The platform is currently the tallest offshore tripod platform in the world.

INTRODUCTION

The South Pass 52 platform is a six-slot, pile-supported steel platform in 531 feet of water which supports a drilling rig and production facilities for 60 mmscfd of gas. The combination of relatively low gas production rate and deep water made this prospect a marginal one requiring an economical structure. The general configuration of the jacket and deck is shown in Fig. 1. The jacket is supported by three 72" diameter skirt piles penetrating to depths of 430 to 470 feet below the seafloor. The deck consists of a main deck and a production module. The minimization of weights and areas was accomplished in the deck and module by designing to tightly accommodate a particular drilling rig, by not providing any quarters except those with the rig, by using the space vacated by the drilling rig for compression after the wells are completed, and by using a three-level module for most of the production facilities. The tripod design minimized weight in the jacket. Gas is sold directly to a nearby pipeline and natural gas liquids are piped to ARCO's Mississippi Canyon 148 platform. More details on the design of the platform were given by Whicher et al (1991.)

The contract for fabrication and installation of the South Pass 52 jacket and deck was awarded in July 1990. Rolling of tubular members began soon thereafter in a fabrication yard on Bayou Boeuf in Morgan City, Louisiana. The jacket was fabricated in the Harbor Island yard near Aransas Pass, Texas. The deck and production module were fabricated and outfitted at two different yards in New Iberia, Louisiana. The jacket was installed in September 1991 and facilities were started up in early 1992. This paper describes the work done to prepare for and complete the load-out, transportation and installation of the platform.