bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Improved Lightweight Bottom-Founded Offshore Platform
Authors: Lewis R.E. 
Published: October 2008

ABSTRACT
This paper presents the design and analysis of an improved lightweight, bottom-founded, offshore platform for multi-purpose use in support of field development operations in water depths to 500 feet and possibly greater, and in severe as well as in mild marine environments. The concept, an innovation based on current tripod-type structures, utilizes a novel framing support system which results in an extremely efficient design with a broad range of applicability. The development of diverse applications for the concept and an assessment of its limits of applicability are discussed.
This paper is of interest to the designer, the engineer, or others wh O are seeking an alternative, straightforward and cost effective approach to the design and installation of offshore platforms. The data presented is useful to those assessing the economic feasibility of an offshore field development.
The paper discusses platform performance data, including member stresses, deflections, and natural periods of vibration, and offers criteria related to the environment, payload, and water depth for which the concept is best suited. Estimated platform weight and cost data versus water depth for various environments and development scenarios are presented and compared with data from more conventional platform concepts. It is demonstrated that the improved concept offers significant advantages over current designs.

OBJECTIVE OF THE DESIGN
This design concept was developed in response to the ever growing need for more cost effective solutions to the development of our offshore hydrocarbons reserves. The objective of the design was to develop an offshore structure that 1) is very lightweight, 2) has a relatively high deck load capacity, 3) is suitable for use in a large range of water depths, 4) is adaptable for the pre-drilling and completion of wells, 5) can be fabricated in a relatively short period of time, 6) can be installed with conventional lifting and/or drilling equipment, and 7) can be easily relocated for reuse at another offshore site where the water depth differs greatly from the first site.

GENERAL DESCRIPTION
The basic concept is a tripod structure as illustrated in Figures 1 to 3. The configuration shown in these figures is called a "Right Angle" configuration because it appears, when viewed from the side, as a 90Â° right angle. The right angle configuration offers greater access for the drilling of wells. In a "symmetrical" configuration the apex of the tripod is placed at the centroid of the triangular base. The symmetrical configuration is suitable for those applications that do not have wells.
The principal component of the structure is the column. The column is designed as a separately installed element which is lifted or floated into place offshore in a single piece. It may contain risers, umbilicals, sumps, caissons, and other facilities as needed for offshore operations. The column is designed to support a cantilevered equipment deck.
Design And Installation Of A Cost-Effective Spar Buoy Flare System
Authors: Korloo Jafar 
Published: October 2008

ABSTRACT
To meet the requirements of flaring large amounts of gas, a cost effective Spar Buoy Flare (SBF) system was designed, built and installed by IMODCO in less than a year at AGIP Petroleum's Agbara field production platform, offshore Nigeria. The system is designed to withstand the 100 year return storm and is capable of flaring 116,500 m3/Hr of gas at an exit velocity of 150 m/s.
This paper presents the system development design, installation, model testing of the Agbara SBF system.

INTRODUCTION
To meet increasing gas production rates disposal requirements at the Agbara field, Nigeria, a cost effective Spar Buoy Flare (SBF) was designed, constructed and installed within ten months. The Agbara platform was designed originally with an integral flare boom for gas disposal. The increasing production required the need for a system capable of remotely flaring large amounts of gas from the offshore platform.
The gas is flared continuously through a 17 inch internal diameter flexible pipe that runs from the production platform to the SBF structure.
Compared with other types of remote flaring structures such as bridge and platform, tripod and articulated type the SBF offers the following advantages:SBF's light weight structure is efficient and particularly suited to deep water.SBF is fabricated in cylindrical sections and is designed for easy local assembly.SBF can be installed with light offshore equipment.SBF can be adapted to different sites.An SBF is a cost effective system especially when considered on a turnkey basis.SBF variable ballast allows for maintenance of splash zone and inspection of chain stoppers.
The general arrangement of the Agbara SBF is shown in Figures 1 and 2.

SBF DESCRIPTION
The SBF is an all cylindrical welded steel structure with an upper section that is 21 m long with a 1.6 m diameter, and a lower section that is 45 m long with a 2.25 m diameter. Between the upper and the lower section is a transition cone which is 2 m long.
The SBF has eleven watertight compartments. The spacing of the compartments allows for accidental flooding of any one compartment without losing stability. The bottom three compartments are used for permanent and seawater ballasting. The bottom compartment is designed for high density ballast, The SBF structural arrangement and the installed configuration of the SBF are shown in Figures 3 and 4.
The major components of the SBF include:SBF pipingChain stoppers interfaceFlare tipWalkway, ladder and boat landingBallast/venting pipingMooring systemCathodic protectionFlexible pipeBallast system
The Agbara SBF structural mass is approximately 100 tonnes; total installed displacement is approximately 200 tonnes.

Flare Piping
The transition piping from the flexible pipe to SBF is provided at approximately 23 m above the SBF keel, The pipe penetrates the decks through seal welded collars that maintain the watertight compartments. Provisions are made to allow the pipe to expand thermally in theaxial direction.
High-Pressure Gas Swivels For A New Generation Of Fpso Systems
Authors: Drijver F.P. , d&apos;Hautefeuille B.B. , Pollack Jack 
Published: October 2008

ABSTRACT
The use of tanker based Floating Production, Storage and Offloading systems has been restricted due to the throughput and pressure limitations of the multiple swivel assembly, which is the key element of the gas and fluid transfer system of a weather vaning Single Point Mooring system. This paper outlines the state of the art of high pressure swivels, particularly for gas applications. It also describes the development of three prototype high pressure gas swivels. The latest constructed one, is a twelve inch pipe diameter toroÏdal gas swivel with a 1900 mm (75 inch) seal diameter, designed for 30 MPa (4350 psi) and 125°C (257 F). The availability of high pressure swivels with very large seal diameters, enables the single point mooring systems to handle larger throughputs of gas, crude oil and other fluids, while several spare swivels can be included in the stack to increase redundancy and future expansion.

INTRODUCTION
Single Point Mooring (SPM) systems are used for loading and offloading crude oil tankers and for tanker based Floating Production, Storage and Offloading (FPSO) systems. The use of SPM for FPSO application has been restricted due to the lack of reliable large gas swivels due to throughput and pressure limitations. The multiple high pressure swivel assembly designs (figure 1) are today all based on individual stackable toroÏds. This stackable modularity allows for the addition of one or more paths to an existing swivel assembly for expansion reasons and it allows the change-out and repair of a defective swivel without disassembly of the other modules. The toroÏdal modules have a central opening for the piping of above placed swivels. The required size of this opening depends on the number and size of pipes connected to these above swivels. Consequently, the bottom swivels need the largest central openings and have therefore the largest seal diameters. The assembly of a large number of swivels was restricted due to the limited central opening size of the largest available high pressure swivels. High pressure swivels with large seal diameters are, therefore, required to overcome the throughput and pressure restrictions of multi path swivel assemblies, The essential aspect in the design of swivels is the sealing of the product between the relatively moving parts of a swivel. Due to the basic concept of the toroÏdal swivel designs, sealing is required around the circumference of a relatively large diameter. The sealing of small and medium size fluid swivels (up to 1,5 meter seal diameter) is achieved with standard sealing techniques, which have been extrapolated to the swivels' diameters, The standard swivel concept is based on this sealing arrangement and has been proven to be reliable in various tests and many real applications. The sealing of gas, however, is very difficult due to its low viscosity and the risk of fire and explosion in case of leakage.
The Application Of Horizontal Wells To The Troll Oil Development:An Operational Review
Authors: Jacobsen R.I. , Rushworth Philip 
Published: October 2008

ABSTRACT
Under the large gas accumulation of the Troll field lies a significant quantity of oil. However, this oil is contained in thin layers distributed over a wide area and therefore cannot be developed using conventional wells.
In 1988 Norsk Hydro re-evaluated possible development schemes for the oil resource, and concluded that the application of horizontal well technology could provide an economically viable means of developing the resource. Appraisal and development study activities were started which included the drilling, completion and testing of 2 horizontal wells. The success of these two wells confirmed that horizontal well technology could be applied to a full scale development.
The operator evaluated a wide range of development options based on the use of horizontal wells, and prepared a comprehensive development plan. The plan was submitted to the Norwegian authorities in December 1991, approximately 3 years after taking the decision to drill the first well.

INTRODUCTION

Background
The Troll field is located offshore Norway in 300m water depth (Figure 1J. The field is divided into 3 areas, Troll East, the Troll West Gas Province (TWGP) and the Troll West Oil Province (TWOP). The individual areas and the hydrocarbons in place are shown in Figure 2. The oil resources are located in thin layers trapped between large gas caps and an active aquifer; Figure 3 shows a cross section through the 3 provinces.

The Use of Conventional Wells
Development of the oil layers using conventional wells was evaluated in 1985 and 1986. Due to the high permeability and the presence of the overlying gas cap, conventional wells could not sustain sufficiently high oil rates and quickly began to cone gas in increasing quantities. Furthermore, a large number of subsea wells were required to develop the field resulting in unacceptably high costs.

The Use of Horizontal Wells
Studies in 1988 concluded that horizontal wells could be used to develop the oil reserves in the 22-26m oil layers in the TWOP. The principal advantages were perceived to be:Higher oil rates at reduced drawdown thereby minimising oil and water production.Longer production period before gas breakthrough thus providing high initial oil production rates.Higher oil recovery per well with lower cumulative gas production.Fewer wells required and hence lower investment costs.
To support these theoretical conclusions it was decided to drill and production test a well in the TWOP. The success of this well lead to the decision to test a horizontal well in the 12–14m oil layers of the TWGP.
This paper describes the design, planning and execution of the drilling, completion and testing operations with the main emphasis on practical and operational considerations. How the experience gained from the wells is being applied to the full field development is also described.
Subsea Processing System Ready for Gulf of Mexico Field
Authors: Lovie P.M. , Baugus V.E. , Grecco M.G. , Schutter D.S. 
Published: October 2008

ABSTRACT:
Use of subsea processing (i.e. subsea separation and Single phase pumping) to produce smaller more remote oil fields has been the subject of field tests and studies since 1969, reported in 9 OTC papers from 1974-1992.
The advance in GLASS [a] is to create a relatively "low tech" and proven solution. Although originally intended for the Gulf of Mexico, it may be applicable in Brasilian, North Sea and other areas. Parallel with the engineering development, composite judgments have been developed for the economic performance for CAPEX and OPEX using recently available probabilistic methods. Connector advances in 1991–1992 may further simplify use of this system design.
Application is relatively insensitive to water depths, e.g. 300–3,000fi. Offset distances from a host platform may be in the region of 5–50 miles. The system was developed for a Base Case in l,500ft. of water with 12,000 bopd initial production with 8 wells from a 25 MMBBL recoverable reservoir, with GORS in the region of 1,000 scf/bbl. Installation equipment comprises the semisubmersible drilling unit and standard offshore service vessels, implying economy and flexibility for use in worldwide application. Hydrate, sand, shutdown and startup operating conditions were addressed.

PRECEDENT SINCE 1969:
The first trials for a subsea processing system were the experiments in 1969-1971 offshore Abu Dhabi at the Zakum field, conducted by BP and Total when they installed a subsea separator and booster pump in about 72 feet of water and operated the system over a three year period, including a year long period when about 1.7 MMBBL of oil was produced. OTC paper no. 1942 in 1974 outlined this pioneering effort.
That prior work was systemized and updated for North Sea field conditions in the GA-SP project (e.g. 30,000 bopd from 4 wells in 984 fl. of water), culminating in full scale prototype trials in a dry doc kin 1990on behalf of eight operators: it was reported in OTC papers 6722, 6766 and 6767 in 1991. This system design used water injection hydraulic power to drive the booster pump, a 4 level component arrangement and a multiple stage subsea separator to provide oil of export quality from a hypothetical arrangement of 4 producing wells with 4 water injection wells, with GORS of about 450. Another series of experiments with a subsea separator was made in live offshore conditions in about 248 ft. of water, near the base of a platform in the North Sea operated by Hamilton Brothers. This test series with the BOET separator design is reported in OTC paper nos. 5922 and 6423 in 1989 and 1990, respectively. It would therefore appear that significant precedent now exists for subsea processing - indicating it is concept whose time has arrived.

ENHANCED RECOVERY FROM REDUCTION IN WELL BACK PRESSURE:
A major benefit of the use of subsea separation and boosting in deep water is that the back pressure on the wells can be reduced and total recovery can be enhanced.
Grid Tensioning System: A New Approach To Deepwater Riser Tensioning
Authors: de Paiva Leite A.J. , Paiva Filho E.F. , Cardellini David 
Published: October 2008

ABSTRACT
The move towards deeper waters for oil and gas production over the past decade, has resulted in higher development costs.
The use of floating structures with surface completion and rigid risers is an attractive approach for development in this scenario.
This paper presents a new riser tensioning concept designed for a so-called "minimum heave" semi-submersible (ref.1). Sixteen risers are connected to a common grid-like structure supported by twelve pairs of tensioners placed around its outer perimeter. Computer based analysis highlights the significant design considerations for this concept and, finally, a comparison is made with individual riser tensioning.

INTRODUCTION
Their small sensitivity to increases in water depth, make floating systems a natural option for deep water hydrocarbon developments On the other hand, the costs of subsea equipment, their installation and maintenance as well as the higher risks involved in subsea completion (sand production, wax formation, leakage control, etc...) pave the way for floating systems with surface completion. This option involves, however, motion compensation and minimization.
The traditional method of providing motion compensation for a large number of steel risers on a floating platform is to provide a separate set (usually four) of tensioner assemblies for each individual riser.
This approach works quite well when the vertical stroke of riser top is limited to around 6 to 9 ft (1.8 to 2.7 m) as in the case of TLP's.
When designing a semi-submersible with dry completion, however, where the stroke can surpass 20 ft (6 m), the wellhead arrangement becomes very complex if individual riser tensioning is to be used.
Other undesirable consequences in this case, are long stroke tensioners of relatively low tension capacity, leading to either unstable, long rod cylinders of normal working pressure, or heavy and costly, low working pressure cylinders of a more stable structural design. Direct tensioning becomes also difficult to accommodate due to the large vertical clearances needed in this case and their quite negative consequences to the platform's stability.
A different approach to supporting a number of risers from the seabed to a floating vessel has been developed. This approach is loosely referred to as the "grid tensioning concept"and is suitable for both semisubmersibles, TLP's or any other type of offshore system where motion compensation/riser tensioning is of concern.
The concept consists of a group of risers connected to a common grid-like structure. The grid itself is allowed to articulate with respect to the vessel, and is connected to it via a series of compensated tensioners arranged around the perimeter of the grid.
The grid is allowed to move vertically within the vessel's moon-pool and to tilt about any axis in the horizontal plane.
The concept was applied to a so-called "minimum heaven semi-submersible (ref.1), where 16 rigid risers are supported by a grid using 12 duplex tensioners.
Design, Construction, And Operation Of A Novel Well Control System
Authors: Marschke C.R. , Wu Nanping , Alcocer C.F. 
Published: October 2008

ABSTRACT
This paper presents the development of a new revolutionary oil/gas well control system. This system has been created to provide effective control and management of oil/gas wells under diverse abnormal situations. The system is versatile in its capabilities and can be used offshore and onshore. The system main/y consists of a cutting tool, a specially designed plug/valve, supporting structures and a power system.
This paper describes the prototype of the new system and the results of laboratory tests simulating the actual conditions of operating oil/gas wells, Actual casing and tubing arrangements were used in the laboratory tests. Finite element Analysis (FEA) and force and stress/strain analysis were performed to design the system and to ensure the integrity of the structure of the well during control operations.

INTRODUCTION
There is an increasing need for systems to be used to fully control wells on fire due to explosion or blow-out, inactive wells where the master valves are not operational due to corrosion problems, and wells where the wellhead has been damaged accidentally during drilling, storms and/or repair operations.
A novel oil well control system has been developed and a prototype has been tested recently. It mechanically blocks the oil path regardless of the condition of the wellhead and/or master valve(s).

EQUIPMENT DESIGN AND CONSTRUCTION
The principle of operation is first to drill through the casing and tubing and then to use the plug/valve system to block the flow of oil/gas and bring the well under control. The system mainly consists of a operation mechanism and a supporting structure. The operation mechanism is mainly composed of a cutting tool, a plug shaft and a hydraulic motor, and the supporting structure includes a yoke and a saddle, as shown in Fig. 1.
Following, are highlighted some design features and the FEA and force and stress/strain analysis, which were performed to determine design parameters to ensure a safe and successful operation.
1. CUTTER/PLUG: The uniquely designed cutter/plug is shown in Fig. 2. It has eight blades and two internal holes. One is for removing the cut material and the other provides a oil path for re-operation. The plug is hardened and tapered. Completely shutting off both the production casing and production tube relies on a metal to metal seal. The pipe material should be sufficiently stressed but not cracked.
A FEA computer software1 was utilized to locate the high stress concentration areas and to find the magnitude of the maximum stress to prevent the material from being overstressed, FEA is a numerical method for stress and strain analysis. It divides a structure into many interconnected elements. Each element has governing equations, force and boundary conditions. With the help of computers, the large amount of equations (with specified force and boundary conditions) are integrated into a matrix form of.