bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seabed Umbilical Stability Analysis
Authors: Hossain Mohammad Kabir , Tjok Ko-Min , Nobahar Arash 
Published: October 2008

Abstract
Subsea umbilicals are widely used as an essential component in offshore oil and gas recovery and production facilities to transport chemicals, hydraulic fluids and electrical power and signals. The umbilical layout on the seafloor usually has a straight section near the riser touch-down-point (TDP) connected to a floating unit, followed by curved sections further beyond on the seabed. The heave motions of the floating unit at the sea surface due to environmental loading can induce cyclic tension loads on the umbilical at the seafloor and move the TDP location, resulting into axial, lateral and vertical motions along the umbilical. In addition to altering available umbilical embedded length this can also alter the field layout and may constitute violation of the design assumptions. This paper describes the results of a parametric analysis of an umbilical static stability with curved and straight sections, in a deepwater Gulf of Mexico seafloor environment, using finite element method (FEM). The finite element model of the umbilical and the surrounding soil was constructed using thin-walled, pipe elements and non-linear springs, respectively. Both, soil resistance to axial and to lateral motions along the umbilical were modeled. Degradation of soil shear strength due to cyclic loading was considered. Umbilical responses to increasing bottom tension loading at the TDP for a selected set of embedment, axial stiffness, radii and lengths of curved sections were examined and the axial and lateral displacements along the length of the umbilical are presented. Based on the results of the parametric analysis, a simple procedure for estimation of umbilical ultimate bottom tension load is presented.

Introduction
A parametric study on the stability of a subsea umbilical was performed and the response characteristics of the umbilical to increasing bottom tension loads were investigated. The effects of the following parameters were studied: umbilical layout and embedment, and umbilical axial stiffness. In this paper, the results of the parametric study and the procedures used in the analyses are presented.
A schematic illustration of a subsea umbilical layout and its embedment is presented in Figure 1. The primary umbilical layout components are: the straight section from the TDP to the start of the curved section (L), the radius of the curved section (R), and the angle of the curved section (f). Umbilical embedment depth into the seabed (H) is shown as a ratio (k) of its diameter (D). The bottom tension load (F) is applied at the TDP.
The Impact of the Use of the Full QTF on LNG Moored in Shallow Water
Authors: Brun Cedric , Naciri Mamoun , Rezende Flavia Caldi , Mombaerts Johan 
Published: October 2008

Abstract
The prediction of slow drift motions for the design of a mooring system is usually made using the Newman approximation [1], based on the assumption of a very low resonance frequency of the system and small contribution of the second order wave fields. This hypothesis is commonly satisfied for most parts of the mooring systems in deep water. However, this is not the case for LNG terminals moored in shallow water.
Unlike the Newman approximation, the FullQTF formulation to compute the low frequency wave loads is more accurate but requires much longer time of computation, which presents limitations in practice when a large quantity of simulations is needed.
Further to the work presented in [2] on the quadratic transfer function (QTF) of low-frequency loading, a new approximation has been developed in [3]. The F1 approximation gives comparable results to the FullQTF and presents the interesting aspect that the loads time series can be reconstructed by means of simple summations, presenting the same efficiency in computation time as Newman approximation.
In this paper, main parameters of mooring systems are analyzed to evaluate the impact of the choice of each method, Newman, F1 or FullQTF. Indeed, this choice is a compromise between calculation time and accuracy of results. The conclusions raised are underlined in the study of an LNG terminal.
Mature Offshore Fields Rejuvenation Via Long Reach Wells and Massive Hydraulic Fracturing: the Kitina Case History
Authors: Tealdi Loris , Rampoldi Maurizio , Casero Alberto , Malonga Henri , Okassa Fabrice , Baioni Antonio , Obondoko Gaston , Itoua-Konga Félix , Isella Davide , Baldini Davide , Riccobon Leone , Pounga Francois 
Published: October 2008

Abstract
Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, the capital expenditure associated to this kind of interventions of critical importance. It follows that the selection of the right and most remunerative well activities is crucial.
In the Kitina Field, offshore from Pointe Noire, Congo, deeper sands have been produced to economic depletion and reservoir studies allowed the determination of alternative production intervals for production maintenance. Large quantities of reserves can be found in low permeability, consolidated, formations as well as in very deep and remote culminations.
From March 2007 to June 2007, the Kitina field production increased of 80% reaching a production level lost since early 2004. This was achieved by infilling the Kitina South culmination with the long reach and ultra deep well KTM-SM5 and via a massive multistage hydraulic fracturing campaign carried out on the three wells draining the low permeability 3A reservoir. These represented the first applications in Congo of such technology. Eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the with very encouraging production improvements. A stabilized production increase ranging from 2 to 3 times was achieved.
The paper describes the unique reservoir modeling, operation geology, and drilling, completion and production challenges encountered in the 2007 Kitina successful rejuvenation campaign. In particular, it focuses on the successful multi-stage hydraulic fracture campaign carried out on four wells of the Kitina 3A reservoir from the preliminary design and production forecast pre-job to the reservoir model history match and forecast phase post-job.

Introduction
The Kitina Marine, Congolese offshore field, has been discovered through the exploration well KTNM-1 in 1991. Two appraisal wells were drilled later on which confirmed the discovery. The field's production starts up took place in December 14th 1997 via 13 wells (8 oil producers and 5 potentially water injectors).
The Kitina field is composed by the following 5 levels:3A - limestone, sandstone with silty clay2A - Limestone: Oolitic Grainstone/Packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement.2A South Culmination: Oolitic Grainstone/Packstone, bioclastic with good intergranular porosity and intercalation of sandstone with carbonate cement.1A - Sandstone with carbonate cement and limestone.1B - Sandstone with carbonate cement and limestone
Kikeh Development: Delivering World Class Completion Performance
Authors: Webb Tamara , Selamat Kasim , Omar Norjusni F. , Desormeaux Rusty Andrew , Moran Patrick M. 
Published: October 2008

ABSTRACT
The Kikeh Development is the first major deepwater project in Malaysia, located offshore Sabah in 1,320m water depth. This 34 well oil development includes Dry Tree Unit (Spar) and subsea producers as well as gas and water injectors.
The Kikeh Field architecture, as well as its subsurface characteristics, required many different completion types to meet the project goals. Early wellbore construction design and rig selection focused on performance while still achieving subsurface strategic requirements. Throughout the design and implementation, many challenges were met in upscaling suppliers to meet deepwater completion needs and managing multiple external interfaces. Great emphasis was placed on working as many activities as possible offline. In addition, lessons learned were captured and implemented immediately, thereby shortening the learning curve impact.
This paper will discuss how these early decisions benefited long-term performance and will describe the grassroots effort for deepwater completion implementation in a new region of the world. Lastly, focus will be on the completion performance, including time, non-productive time and skin describing methodology and techniques used to deliver the Kikeh Development with world-class time and skin results.

INTRODUCTION
The Kikeh Field architecture consists primarily of a Dry Tree Unit (Spar), three subsea manifold sites, FPSO and a pipeline system. The wells include 16 subsea wells and 18 dry trees which were drilled and completed by two different rig types. The field's wells and facilities are designed for peak production and injection rates of 120,000 BOPD and 260,000 BWPD respectively. Figure 1 is an illustration of the field layout and its components.
Completion operations play a major role in the overall Kikeh deepwater development with 25 percent of the total field development CAPEX and 58 percent of the well CAPEX attributed to the well completions. In addition, aggressive production and injectivity skin targets were set as the development thresholds to successfully achieve peak targets. At various levels, the completion design and execution interfaced with each of the facility components and was driven extensively by the subsurface characteristics to optimize production, injection and reserve recovery. The following subject matter discusses the steps taken from design through field execution that were the basis for achieving remarkable results at Kikeh.
Offshore Concrete Structures By Hydraulic Aspects
Authors: Torum Alf , Larsen Per K. , Hafskjold P.S. 
Published: October 2008

ABSTRACT
If large enough, a gravity structure in reinforced concrete will have no problems in overall safety.
Reduction of the dimensions, however, may change this picture. This became evident to Ingenior F. SELMER A/S when modifications of the company's large offshore platform 'design - of 1970 - to more moderate units began. An extensive test program was therefore initiated at the River and Harbour Laboratory (VHL) at the Norwegian Institute of Technology, Trondheim.
The research work was mainly concentrated on wave forces, but other hydraulic aspects relate to bottom mounted concrete structures - such as the effect of shock waves, wave damping devices and scour -are also discussed.

1. INTRODUCTION
Based upon long experience and great confidence in reinforced concrete, a very large platform project for the North Sea was forwarded to the Norwegian authorities in August 1970 by Ingenior F. SELMER A/S. Reference is made to [1] for the background of the design and a ore detailed description than is given here:
Figure 1 shows the basic principles - these include a monolithic raft foundation of circular cells - diameter 20 m - with a system of cutting edges protruding 4 to 5 meters below the bottom slab. From the caisson top - 15 meters below sea level - columns carry the platform and serve as wave dampers as well. The platform would have sides of 300 meters length, giving an area of more than 10 acres.
The intention was to collect many activities on one large, safe base to replace structures scattered over a wider area, thus being more hazardous to navigation as well as more vulnerable individually to the impact.
On a gravity structure sufficiently large in relation to the wave length, the wave loads will the of relatively little significance; but as dimensions decrease, wave loads grow more and more important.
Sea bottoms to which gravity structures are applicable are often also vulnerable to scour. At large structures local scour can usually be counter acted in time, at smaller ones the situation may be more serious.
Problems and risks usually increase as the dimensions of gravity structures decrease. For ordinary steel piling structures the opposite is the case.
Consequently the competition between steel and concrete structures may not lead to the optimum field design if the general lay-out has been- based too rigorously on one type or the other.
The advantage of combining two or more ordinary platforms on a single, large concrete raft should especially be Kept in mind since it opens the possibility of a very inexpensive extention of platform area.

2. WAVE FORCES ON LARGE VOLUME STRUCTURES
The calculation. of wave forces. on large volume structures, e.g. structures where drag effects are of no importance has followed two approaches. The first approach is to use a quasistatic approach introducing force coefficients This approach requires measurement of forces on a model or a prototype-structure to determine these coefficients [1], [2].
Kikeh Development: Design of the World's 1st Gravity Actuated Pipe (GAP) Fluid Transfer System
Authors: Brown Paul , Rooduijn Erik , Lemoel Marc Guy , Stone Geoff , McFadyen Michael Keith 
Published: October 2008

Abstract
The Kikeh Field is located offshore Malaysia in the South China Sea in a water depth of 1320 m. This field development is based on a Floating Production Storage and Offloading unit (FPSO) and a Dry Tree Unit (Spar). Fluids between Spar and FPSO are transported in Fluid Transfer Lines (FTL) based on the first ever application of the patented Gravity Actuated Pipe (GAP) system.
This paper presents an overview of the FTL GAP project for the Kikeh development, which was awarded to Delcom / SBM under an EPCIC contract in April 2005. This paper provides a description of the key project execution achievements and technical solutions. The Kikeh FTL GAP project commenced fabrication activities in 1st quarter of 2006, with offshore installation completed (Figure 1) and first oil achieved in August 2007.
The GAP technology enables development of a deep water field with an FPSO plus Spar without the fluid transfer system touching the seabed. Dry trees have the major advantage of easy surface access such that intervention costs and risks during operation are better controlled. Combining a Spar with fluid transfer to an FPSO system gives a robust field architecture with ‘building block’ flexibility for phased field development.
The GAP principle is based on a large diameter carrier pipe supporting a number of flow lines and umbilicals, with the carrier pipe serving as a structural support. Tether chains are suspended from the floaters to support each end of the carrier pipe. Clump weights or buoyancy are mounted at the ends of the carrier pipe to generate vertical load. The action of the clump weights or buoyancy on the angled chains keeps the carrier pipe under tension. This tension minimizes the hog /sag deflections of the carrier pipe bundle and keeps the GAP system within acceptable hog /sag limits.
The GAP system is an attractive alternative solution to seabed flow lines. The main advantages of the GAP are:improved flow assurance due to higher sea-water temperature leading to reduced risk of blockage by formation of wax and/or hydrates;lower discharge pressures since overall flow line lengths are shorter;avoidance of seabed constraints, for example ground instability, irregular sea-bed profile, subsea hardware congestion.
Self-Erecting Gravity Type Steel Platform for 350 to 500-Ft Water Depths in North Sea By Production
Authors: Minorsky Vladimir U. , Sharman Hugh U. 
Published: October 2008

ABSTRACT
The concept of a two stage jack up drill rig for deep water as developed by George G. Sharp, Inc., was described at the 1973 aTC meeting: in the present paper the concept is modified to suit a steel production platform and utilizes cylindrical legs instead of trussed legs. Storage of more than 500, 000 barrels can be provided in the legs and in a mat. While the design described was developed for 380 ft. of water, it-could be made to apply for depths of water exceeding 500 ft. competitively with other deep water platform concepts.

INTRODUCTION
In the search for oil in the North Sea properly designed semi-submersibles have proven to be satisfactory tools, despite experiencing difficulties with the placement of anchors and with downtime in general. To date, there is not an equally satisfactory general solution to the installation of production platforms in deep water.
The demand for such platforms in the next ten years. is expected to be very strong, with perhaps as many as f gutsy or one hundred platforms needed to bring out oil estimated at forty billion barrels.
Extrapolations of platform installation methods successful in the Persian Gulf and in the Gulf of Mexico to deeper water applications in the North Sea are not valid, because of the weather conditions. Platforms in the North Sea are subjected to much larger overturning moments because of greater water depths and far more severe wave forces. Further, the season for work on the site is quite short, and site work using conventional means of construction during the off season is either impossible or subject to prohibitive downtime.
An insight into the magnitude of the North Sea challenge may be gained by reading about the difficult problems faced and solved by B. P. in connection with the large templates building for their Forties Field. Specially designed equipment to cope with the installation work includes an enormous hammer that will deliver 630,000 ft.lbs. of energy per blow and cranes capable of 1200 ton lifts, Ref. (1): needless to say, the rental of such equipment becomes very costly.
In discussing North Sea platforms, mention must be made of the bold and innovative concrete tank and production platform designed by C. G. Doris and Phillips Petroleum for Echoism 1. Almost all the engineering problems were solved while it was fjord based, so that construction time on site was reduced to a minimum.
There is of course no proper basis of comparison between the solution at Ekofisk I and that at the Forties, since the bottom conditions and depths of water are quite different. Moreover, it would not be economical to extend the Ekofisk solution to greater water depths without radical modifications. Recent articles, Refs. (2), (3) and (4), have described gravity platforms mounted on one or several shafts projecting from a hollow concrete foundation.
Fracture Mechanics-Based Fatigue Predictions for HPHT Equipment
Authors: Cordes Roger , San Pedro Ramon I. 
Published: October 2008

Abstract
A methodology covering fatigue life predictions for high pressure high temperature (HPHT) equipment is presented. HPHT equipment is generally thick-walled and by a common definition involves pressure ratings of 15,000 psi and above and temperature ratings of 350ºF and above. A fracture mechanics-based approach is described including the crack growth methodology and the determination of the design life. The approach is similar to that used in the ASME Boiler and Pressure Vessel Code and discussion is presented including a comparison to engineering criticality assessments (ECAs) covered in API recommended practices and in British Standards. The application of safety factors through input variables and through the analysis methodology is discussed. The limitations of S-N fatigue analysis for the evaluation of thick-walled high pressure equipment are also discussed.
Example problems are presented to display the application of the method to subsea equipment. The stresses are examined on a series of cylinders with several wall thickness to diameter ratios. This includes a cylindrical vessel with dimensions similar to a wellhead housing. The finite element method is used to determine the appropriate stress profiles through the thickness for the extreme loading and the cyclic loading.
Several sensitivity studies are performed to display the influence of the inputs. The relative importance of material toughness (i.e. CTOD or KIC) and residual stress are discussed. While their values are generally important, they can vary widely without influencing the fatigue life prediction. The influence of other material properties, such as the crack growth constants, and residual stresses are also discussed.

Introduction
The design verification of equipment for high pressure high temperature (HPHT) applications, typically defined as those requiring pressure ratings of 15,000 psi and above and temperature ratings of 350ºF and above, will require thinking beyond the " tried and true?? analysis methodologies used in the oil industry for the past couple of decades. Recent changes in and continued development of relevant codes and standards will surely impact the oil field equipment industry in the near future.
The material selection for HPHT components is critical to ensure adequate life. Deep reservoirs can bring about high partial pressures of H2S and corrosive by-products. High temperatures can alter material properties, behavior, and failure mechanisms. While these problems are significant, they are further complicated in that many HPHT components have additional functional requirements. In many cases, factors other than internal pressure (such as excessive deformation, sealability, functionality, fatigue) may limit the design pressure or require wall thicknesses beyond that needed for internal pressure alone.