bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Flexible Pipe System Replaces Submarine Hoses In SBM
Authors: Heijst Willem J. 
Published: October 2008

ABSTRACT
The application of single buoy mooring systems as offshore terminals for VLCC's is now generally accepted. Large diameter hoses - 2 or 3 strings parallel - are used to transfer the crude oil from the sea bottom pipeline manifold via the terminal to the tanker manifold, or vice versa.
When the submarine hoses are replaced by articulated piping (comprising a vertical pipe connected to the SBM and a horizontal pipe connected to the sea bed, both sections linked together and all connections being made by universal joints), the reliability of the terminal will be strongly improved if the components of this pipe system are properly designed.
The design criteria have been obtained from extensive model tests on single and double systems and through calculations, whilst the components of the flex pipe system are and have been tested on full-scale. Great care is given to fatigue strength to predict life-time of the system on site and maintenance procedures are studied and tested on full-scale to prevent any unexpected situations when installed.

INTRODUCTION
The single buoy mooring system, apart from acting as a crude oil terminal, is also employed for the transfer of other fluids, in particular petro-chemicals, bunker oil, gas and even iron ore slurries. Until now the underwater link between pipeline manifold and the SBM has been provided by flexible hoses.
This hose string must be relatively long in order that the buoy may ride easily and without restriction on the sea surface at high tides and at maximum expected wave heights. At low tide, the hose string should not bend beyond the safe bending radius, nor chafe along the anchor chine or along the bottom. Finding the right length of hose string and configurations to meet all these criteria presents a certain amount of difficulties.
Two basic configurations in use are the Lazy-S and the Chinese Lantern, both based on a delicate balance between the rigidity and an equilibrium obtained by counter-balancing the hose weight with either buoyancy tank or floats. Factors which disturb this balance are currents, waves, buoy motions and changes in the specific gravity of the fluids pumped through the hose. Static model tests are usually carried out to define the optimal lay-out, and in some difficult situations the dynamic behavior of the underwater hose lay-out has been tested in the NSMB model tank basins in Wageningen.
The design of an underwater hose lay-out for Several large diameter hoses in parallel for rough areas with strong tidal currents is extremely difficult since the radius of permissible bend is obviously large for such hoses and the deviation that can be tolerated from the neutral position is therefore small.

THE FLEXPIPE SYSTEM
In order to overcome the restrictive requirements for the application of an SBM using such hoses, the "Flexpipe" system has been developed. The system comprises a vertical pipe connected to the SBM, and a horizontal pipe connected to the sea bed pipeline manifold.
Alaskan Beaufort Sea Exploration and Production Islands - Civil Design and Construction
Authors: Lucas Jim , Masterson Dan M. , Hall Jerome D. , Perry Conrad Joseph 
Published: October 2008

Abstract
A civil engineering perspective is presented on the design and construction of exploration and production islands in the nearshore Alaskan Beaufort Sea. Pioneer Natural Resources' 2003 Thetis exploration ice islands and the subsequent 2006 Oooguruk production island in East Harrison Bay are highlighted. Engineering design issues are discussed including special techniques required for the severe ice, wave and permafrost environment. The effectiveness of using frozen gravel foundations, which must be designed for seabed settlement, gravel thaw-settlement and creep settlement, are discussed. Construction techniques and schedules have been developed to make use of the readily available ice and gravel. Monitoring performance is an important post-construction activity. Potential issues are identified with preventative and remedial solutions described.
Three offshore exploration wells were drilled using conventional land-based equipment from grounded ice platforms during the course of one winter. Subsequently, a gravel production island was built in the same area using material hauled from shore. Seabed settlement and the thaw instability of frozen gravel are uniquely addressed in the design and construction of the island.
An economical approach has been described for building temporary exploration structures and permanent production structures in shallow, protected nearshore waters of the Alaskan Beaufort Sea. The methods have applicability for accessing smaller offshore oil and gas fields in the Alaskan Beaufort Sea and in other cold regions of the world where similar marine conditions exist.
Site Characterization through the Integration of Geophysical and Geotechnical Data
Authors: Ehlers Clarence J. , Lobley Graeme , Spikula Daniel Robert , Brand John Richard 
Published: October 2008

Abstract
This paper illustrates how the integration of geophysical and geotechnical data can be used to characterize and provide an explanation for variations in soil properties across a deepwater development site.
At a deepwater offshore development site, a high-resolution geophysical survey identified the presence of current scour features at the seafloor, in-filled and buried scour features, and thinning parallel-continuous stratigraphy across the site. A subsequent geotechnical investigation was performed at three anchor cluster locations with Piezocone Penetration Tests (PCPTs) and Jumbo Piston Cores (JPCs) targeting areas both inside and outside of the scour features to assess soils variability. The investigation revealed the presence of sand in one surficial scour feature, no significant change in shear strength within a buried scour feature, the presence of deep, localized " weak?? soil zones at varying depths with sudden 25 to 30 percent decreases in cone tip resistance of up to 30 percent, and a variation in OCR across the site.
Integration of the geophysical and geotechnical data revealed that the local presence of sand across the area could not be determined by strictly geophysical data alone and required confirmation with geotechnical data. The " weak?? soil zones detected in the PCPTCPT data could be correlated to a discernable set of seismic reflectors, permitting the mapping of the depth to top of the " weak?? soil zones over the entire site. This in turn allowed the PCPTCPT data to be used to characterize these weak layers, and thus variations in shear strength, across the site. Finally, the thinning stratigraphy due to erosion observed in the geophysical data supported the trend in the OCR and associated shear strength variation across the site.

Introduction
A turret- moored FPSO with a three point mooring system is being installed in about 1100 meters of water at a deepwater oil development site. A shallow, high-resolution, AUV geophysical survey and geotechnical investigation were performed at the development site to investigate seafloor and shallow geologic features and to define soil conditions within the foundation zone of the anchors for the mooring system. The geophysical survey revealed the presence of seafloor and buried in-filled scour features that result from seafloor currents. These results were used in the scoping of the geotechnical investigation, which targeted these scour features to determine if variations in soil conditions might exist. The geotechnical investigation in turn revealed conditions that were not identified in the high-resolution geophysical survey. The results of the geotechnical investigation were then integrated with the geophysical data to identify and explain trends or correlations between the data sets.

Geological Setting
The study area is located along the north flank of a significant submarine canyon as shown by the grayscale seafloor rendering Figure 1.
Model Testing Techniques In Offshore Pipiining
Authors: Clauss Gunther , Kruppa Claus 
Published: October 2008

Abstract
If offshore pipelaying operations are to be simulated at model scale complete geometric similarity can not be maintained. Model pipe cross section dimensions and material have rather to be chosen in a way quite different from full scale conditions, in order to fulfill the relevant scaling laws. Using large deflection beam theory the latter are derived from first principles, allowing for gravity and elastic forces in addition to inertia forces. Recommendations for selecting model pipe material, geometry and possible liquid content are made.
For a mercury fifed Perspex pipe with insert rod model test results are presented. Static deflection and bending stresses are measured over the pipe. length and compared with theory, as a function of horizontal tension forces acting on the pipe head. Dynamic stress fluctuations are assessed for cyclic motions of the pipe head, separately for pure surge and heave

Introduction
Offshore pipe laying operations become more hazardous as depth of water increases and adverse sea conditions prevail. This is the case in present-day North Sea pipelining, where discontinuity in operations is rather a matter of seasons than of days. Under these circumstances it is of utmost importance to he able to predict probability of pipeline failure with a high degree of accuracy, or rather to define wind, sea and current conditions under which a particular pipe laying process has to be interrupted. :'-Jeedless to say that this is largely a function of the sea keeping characteristics of the pipe laying barge or vehicle.
Stress calculations and full scale measurements have so far been the instruments which helped to develop an understanding of the more important factors governing stress levels during pipe laying operations [e.g. 1,2]. Although discrepancies between theory and full scale experiment have been shown to be acceptably small under steady-state conditions, the results so far published are less conclusive with regard to dynamic response [e. g. 3,4 1. Under these circumstances it is hoped that model tests, requiring neglegible funding if compared with field measurements, may help to resolve some of the problems that have so far remained unanswered.
With a small text apparatus set up at the Institute für Schiffstechnik of the Technique University Berlin the authors have carried out some basic experiments, with the intention of showing the validity of steady-state performance calculations and indicating the importance of dynamic response assessment.
In modeling offshore pipelining the number of scaling laws is larger than can be fulfilled by adhering to complete geometric similarity. Therefore model pipe dimensions have to be selected on the basis of a compromise, the extent of which can only be assessed by deriving the appropriate scaling laws, from first principles. This will be done at some length in the following paragraphs, adding some model test results in the subsequent ones.
The Future Drilling Scenario
Authors: Strom Steinar 
Published: October 2008

Abstract
This paper will include:The technical basisThe work processesPlans and visions for the future
The paper gives an overview over field tried equipment, pilot tested equipment and the synergy effect when combing the different technical solutions in future drilling scenarios.
Drilltronics is an integrated control system for real time monitoring and control of the drilling process. Based on mathematical computer models for dynamic real-time analysis of the well behavior, critical limits for operational parameters like drilling fluid pump rate, trip velocity and optimal process parameters are calculated. The result of the calculations is applied directly to control drilling equipment in real time. The Drilltronics system has been field tested on the Statfjord C platform. Combining the Drilltronics system with wired pipe, decision support programs, and continuous measurements of drilling fluid parameters give synergy effects that in future may allow remote operated drilling systems.
To handle drilling through sections with large pressure variations between individual layers or between the overburden and the reservoir future drilling practice will change. Rotary steerable liner drilling systems will be available primo 2008. StatoilHydro and one of StatoilHydro's suppliers are developing a 9 5/8?? and a 7?? system. A full drilling tool package can be included in the system. By combining steerable liner drilling with the expandable pipe technology and managed pressure drilling methods, lot of to-days drilling challenges can be solved.

Background
StatoilHydro has identified Automated Drilling Systems (ADS) as one of our major technological efforts in a relatively near future. The technology as such is to a large extent at hand. It is a matter of taking the technology into operation. Our experience is that many of the drilling problems are related to human error or rather; slow response wrt corrective actions. ADS has the capability, if designed correctly, to eliminate this type of misbehaviour. It is mandatory to design the Automated Drilling Systems such that the general progress in operation is not slowed down.
Deep and Very Deep Oil-Storage Tanks
Authors: Pliskin Lucien 
Published: October 2008

INTRODUCTION
Man is just beginning to anticipate the dizzying wealth hidden in the seafloor as research and production of offshore oil are increasingly developing in deeper waters. Today 150 to 200 m (500 to 600 ft) deep fields are no longer considered as exceptional. Oil companies are now contemplating production in blocks situated in various seas with depths down to 500 to 600 m (1,500 to 2,000 ft). We can expect confidently that within the next 10 years the interest of the oil industry will shift from the present relatively shallow waters to sea depths going down to, let us say, 2,000 m (6, 000 ft), giving birth to important new developments in oil research and production.
Temporary underwater storage of crude oil on the field will be one of the numerous problems to be solved, perhaps even more need fully than for shallow seas.
The Sea Tank Co. performed an active role in the development of gravity underwater storage tanks and platforms to be laid on the continental shelf. 1,2. Now we are extending our field of internet by preparing designs of deep and very deep storage tanks to be used in a range of depth from 200 m (600 it) to 1,000 m (3,000 ft).

GENERAL PRINCIPLES
A first approach of the problem makes it clear that the following principles have to be respected in order to design deep tanks.The structure is to be a gravity structure. Its stability on the seabed will be secured by its dead weight without any piling or anchorage. This condition can be easily fulfilled since the influence of wave forces is very small when the depth is larger than 200 m (600 ft). The main force to be withstood is the uplift force due to the difference of density between the stored oil and the sea water.The tank must not have to withstand external hydrostatic pressure. That means that the stored oil is to be in acupressure with the external sea water. Communication is to be provided between oil and sea. The tank will work following the water-oil displacement principle.There should be no rigid connections between the tank and the sea surface, for exploitation as well as for immersion, because of the great depth taken into account. This point is important since it leads to immersion procedures of the tanks that have to be quite different from those usually adopted for shallower seas. 1,2. In this latter case, the presence of emerging columns or towers acting as floats makes it easy to control the immersion processLast, but not least, the design of such a tank must allow safe, simple, and quick offshore operations. This is particularly important for the immersion operations that must be performed in open sea.
Kikeh Development: Sand Control Selection, Design, and Implementation of ESS
Authors: Omar Norjusni F. , Webb Tamara , Desormeaux Rusty Andrew , Moran Patrick M. , Selamat Kasim , Beare Steve P. , Jones Colin , McWilliam Kevin Charles 
Published: October 2008

Abstract
Discovered in 2002, the Kikeh field is located 120 km northwest of the island of Labuan, offshore Sabah, East Malaysia. The water depth at Kikeh, Malaysia's first deep water development is 1,320m. The field development consists of a dry tree unit (Spar) and two subsea production hubs, all tied back to an FPSO. Two of the three productive intervals in the development were determined to require sand control, representing about two-thirds of the field's production.
This paper documents the selection and design process for a multi-zone sand control completion with zonal isolation to meet the requirements of both the open hole oil producers and the cased and perforated injector wells on Kikeh.
The primary objectives of the system being:Maximize productivity/injectivityProvide efficient sand retentionMinimize cost and timeDesign for well life to minimize workovers and interventionsHave a large bore to maximize the capability for future selective completions
After extensive testing and evaluation was performed on the seven appraisal wells across the field, including well tests with sand control, expandable sand screens (ESS) were selected as the primary sand control method. The evaluation, coupled with extensive local ESS installation experience in both Southeast Asia and Malaysia, gave the confidence that the installation objectives would be met.
This paper describes the evaluation of sand control methods and why ESS was determined to be the best choice for the Kikeh field development. It also describes the details of each ESS type (water injector, producer, and intelligent completion) and the testing required to qualify each system.
Swelling Elastomer Packers were used to provide zonal isolation in both the injector and producer wells. The qualification and selection process for these packers is also discussed.
Significant application learnings will be discussed and, lastly, well productivity and skin results will be reported.

Introduction
Murphy discovered the Kikeh field offshore Sabah in 2002. A seven well appraisal program was conducted, which included well tests (two) with sand control. It was identified at this stage that one of the many challenges that the Kikeh field posed, was to find a sand face completion that could control the relatively unconsolidated, and poorly sorted sands present in Kikeh's geology. The system would have to be truly flexible in its multi-zone capabilities, to safely and efficiently exploit the highly laminated sands in Kikeh, while isolating the shales, throughout the expected 20-year life span of the field. As part of the design case, the system would have to provide a suitable interface for a future selective completion allowing for reservoir management as required.
Oooguruk Project Field Development Concept and Execution
Authors: Hall Jerome D. , Perry Conrad Joseph 
Published: October 2008

Abstract
The Oooguruk project is located in the Alaskan Beaufort Sea and consists of a 6 acre gravel drill site approximately 5 miles offshore in 4.5 feet of water. The drill site is connected to an onshore facility by a complex flowline system consisting of a 5.7 mile subsea buried flowline bundle which transitions onshore to a 2.3 mile traditional North Slope above ground flowline support system. Approximately 38 horizontal extended reach wells will be drilled into two horizons to develop the field. Drilling commenced in December 2007 and the field is scheduled to come online in 2008.
This paper generally describes the Oooguruk field development concept, project execution strategy and the challenges faced during planning and construction. Details regarding island design, environmental design criteria, pipeline design and construction, and drilling rig capabilities are included in other technical papers.

Introduction
In the winter of 2003 (January - April), Pioneer Natural Resources (as operator) and Armstrong Oil & Gas drilled three wells (Ivik No. 1, Oooguruk No. 1, Natchiq No. 1) in Harrison Bay, northwest of the Kuparuk River Unit Field. Pioneer determined that the resource was economic to develop after analyzing the results from these wells and subsequently acquiring well and geological data over the area. Pioneer would develop two separate reservoirs called Kuparuk C and Nuiqsut from a single drilling center.
The development plan consisted of three major components: an offshore drill site (ODS); an onshore interconnect and production support facility (OTP); and a system of flowlines, power cables and communications cables connecting the onshore and offshore facilities. Three phase production would be delivered through an interconnect to existing infrastructure at the Kuparuk River Unit (KRU) drill site DS-3H operated by ConocoPhillips. The location of these facilities is illustrated in Figure 1.
Five wells, three producers and two injectors, would be needed to recover the Kuparuk reserves in the original plan. A total of 33 wells, 18 producers and 15 injectors, would be drilled to recover the Nuiqsut reserves. The estimated recoverable reserves for the project were between 50 and 90 MMBOE. The depletion plan for both reservoirs would require long horizontal wells. Recovery would be enhanced by incorporating water-alternating-gas (WAG) injection capability and by installing electric submersible pumps (ESPs) in each of the production wells. Since the drill site would need to be self sufficient due to isolation during certain times of the year, a Class 1/Class 2 disposal well would also be drilled.