bluuebunny/crossref_metadata_2025_split huggingface dataset:
Jacket Performance due to Foundation-Degraded Response
Authors: Mirza U.A. , Maclaren D.J. 
Published: October 2008

ABSTRACT
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

ABSTRACT
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;&gt;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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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.
Fatigue Life Enhancement of Semisubmersible Rigs
Authors: Chaudhury G.K. 
Published: October 2008

ABSTRACT
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.