bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Stable Platform Characteristics
Authors: Horton E.E. , McCammon L.B. , Murtha J.P. , Paulling J.R. 
Published: October 2008

Abstract
A procedure termed "hydrodynamic synthesis" was described in several earlier papers and has proven successful in predicting the wave-induced motions and anchoring forces for semisubmersible stable platforms. Such a platform responds as a resonant oscillating system to a forcing term whose amplitude and phase vary with frequency. The variation of force amplitude stems from the variation of phase of the forces on various members of the structure. The possibility is explored of exploiting both the frequency response characteristics and the force amplitude characteristics to design platforms of minimum motion or anchor line forces. Several examples are worked out by the hydrodynamic synthesis procedure from which it is concluded that resonant detuning is more important than force minimization in optimizing the heave motion of a floating platform. For the tension leg platform, however, the minimization of wave forces on the structure provides the best means of optimizing anchor cable loads.

I. Introduction
In two earlier papers, Paulling (1970), and Paulling and Horton (1971) have described a procedure which has proven to be quite successful in predicting the wave-induced motions and anchor cable forces for stable floating platforms. This procedure, termed "hydrodynamic synthesis" utilizes a linearized hydrodynamic analysis for predicting the wave forces on the structure. The principal assumptions made in the procedure are as follows:The motion amplitudes for the platform and waves are small.The structure is composed of an assemblage of either cylindrical "members" whose cross sectional dimensions are small compared to their lengths and to the wave length, or small volumes all of whose dimensions are small.The forces are computed for an individual member of the structure as though other members were not present, i.e., hydrodynamic interference between members is ignored.The forces associated with wave motion are computed independently of the forces associated with the absolute motion of the structure.
The structure is then treated as a rigid body having six degrees of freedom for which the equations of motion take the form(Available In Full Paper)
The equations of motion are solved to obtain the × j (t) which describe the motion of the body as a function of time. For an anchored structure, a knowledge of this motion may be then used to deduce the anchor cable forces. If some of the restoring force terms, c ij, are nonzero, the structure will respond to the exciting force as a multidegree of freedom oscillating system. For small values of the damping coefficients, b ij, it is well known that the response, defined as the ratio of the amplitude of motion to the amplitude of the incident waves, becomes large for wave frequencies in the vicinity of the undamped natural frequencies of the system. These natural frequencies, wn are computed by finding the eigenvalues of the system of homogeneous equations corresponding to the undamped free motion of the system,
Semisubmersible Based Dry Tree Platform with Compliant Vertical Access Risers
Authors: Mungall Chris , Haverty Kevin , Bhat Shankar , Andersen David , Sarkar Indranil , Wu Jack , Mårtensson Houston Nils 
Published: October 2008

Abstract
It is shown in this paper that a semisubmersible-FPS can be used as a dry tree platform in ultra-deep water Gulf of Mexico when designed with Compliant Vertical Access Risers (CVARs). The Technical feasibility of the proposed dry tree semi concept is demonstrated by an example application in 8,000 ft water depth. Riser extreme response, interference and fatigue have been analyzed. Installation schemes have been considered. It is concluded that the proposed dry tree semi concept is technically feasible and that it can provide an attractive lower cost solution for dry trees in the ultra-deep parts of the Gulf of Mexico.

Introduction
Dry tree platforms have been used in the Gulf of Mexico in water depths up to 5,400 ft. Studies have shown that it becomes expensive to extend the application of conventional dry tree platform concepts (TLPs and Spars) to ultra-deep water depths such as 8,000 or 10,000 ft. We propose an alternate dry tree platform concept to provide operators with the benefits of direct access to wells from lower cost floating systems such as the semisubmersible-FPS (henceforth 'semi- FPS'). Dry tree wells are tied back to the semi-FPS using Compliant Vertical Access Risers (see Figure 1). The CVAR is attached rigidly to the semi-FPS (see Figure 2) via a flexjoint or a tapered stress joint avoiding the need for flexible jumpers and simplifying deck layout. Unlike a Spar or a TLP, there is no relative motion between the riser top and the vessel in operation, simplifying access to the dry trees and well access during workovers. At the sea floor the CVAR is attached to the wellhead in much the same manner as a Top Tensioned Riser (TTR).
The CVAR, like Spar or TLP TTRs, has the benefit that the riser is vertical at its top and bottom - permitting vertical access. TTRs obtain their compliancy by virtue of relative motion at their tops which is accommodated by tensioner or buoyancy can stroke. CVARs obtain their compliancy from excess riser length. Since the buoyancy is distributed approximately in the middle portion of the riser CVARs have the characteristic shape shown in Figure 1.

Background
The idea of the CVAR dates back (at least) to 1988 when a patent was awarded to Pearce et al [1] for a flexible riser and associated equipment that could be used to obtain vertical access to a subsea well. (The patent belongs to Halliburton/KBR.) KBR carried out a number of early studies in the late 1980s and early 1990s on the feasibility of using CVARs as production and workover risers from floating production systems in 3,000 to 6,000 ft depths. Brinkmann and Whooley [2] describe the use of CVARs with a Spar (also known as Deep Draft Caisson Vessel or DDCV) in 4,800 ft of water in the Gulf of Mexico. However, a study on this subject has not been reported so far.
Coral and Estrela do Mar: The Development of a Marginal Field in Brazil
Authors: Portella Ricardo B. , de Souza Lima Heitor A. , Projemar S.A. , Guimarães Carlos Roberto , Munksgaard James  Nascentes 
Published: October 2008

Abstract
Coral and Estrela do Mar are two oil fields located in Santos Basin, 180 km offshore Southeast Brazilian coast, in water depths of 150 m, that are being explored by a consortium composed by Petrobras, Queiroz Galvão Perfurações, Starfish Oil & Gas and Coplex Petroleo do Brasil.
The field exploration is based on a stationary oil production unit and on a floating storage and offloading unit. Based on a public BID, Petrobras, the leader of the consortium, selected the Brazilian operators Petroserv and Transpetro to provide a semi-submersible platform and a FSO and their operation respectively.
Santos Basin area is a quite unexplored region in the South of Brazil with very few offshore resources. The key issue of the project was the very short time schedule available and the necessary high degree of confidentiability needed for the system due to absence of resources on the field vicinity combined to the fact that this area is located in the middle of an important ocean biological reservoir.
This paper describes the engineering work performed for the development of the oil field that was based on the upgrade of the semi-submersible platform Atlantic Zephyr that received an oil process plant with 20,000 bpd capacity, a new helideck, new drain and firefighting systems, a flexible risers system, a ROV platform and stability blisters and on the conversion of the F.S.O Avaré, a 28,000 dwt oil tanker that received an innovative DICAS mooring system, an oil import riser, a helideck, a new deck crane and an offloading system. Even being a low cost project, the development of Coral and Estrela do Mar meets some remarkable achievements. The short time required to start the oil production, the simplicity of the concepts used for the field development, the environmental aspects involved and the mooring systems using torpedo piles are some of the aspects that give to this field a very special position on the Brazilian oil industry.

Introduction
The recent oil exploration activity in Brazil has been mainly noted in the international scenario due to giant projects for the exploration of the large oil fields discovered in the Campos Basin. Marlim field with P37, South Marlim with P40 and P38, Roncador with P36, Barracuda with P43, Caratinga with P48 and Albacora East with P50 are some of these remarkable projects that demand giant floating units.
Coral and Estrela do Mar, two marginal fields located in Santos Basin on the South part of the country, constitute a completely different scenario on the oil exploration activity in Brazil.
As the offshore oil production in this region is still incipient and the logistic infrastructure almost does not exist, the project needs to be simple, reliable and cost effective. To achieve these goals, it was prepared and approved a development plan for the simultaneous exploration of two fields based on a floating production unit, an oil storage unit and oil export shuttle tankers.
HT/HP Pipe-in-Pipe Snaked Lay Technology - Industry Challenges
Authors: Hooper J. , Maschner E. , Farrant T. 
Published: October 2008

Abstract
The Penguins Field is located in the most northern waters of the United Kingdom Sector of the North Sea, approx. 250km NE of the Shetland Isles, Scotland. The pipeline comprises 66km of Pipe-in-Pipe (PIP) in water depths peaking at 170m. The HT/HP pipeline navigates a sinuous route through boulder fields, isolated rock embedment and clay outcrops, around subsea facilities and over several crossings, in regions subject to moderate fish trawling activity.
The highly insulated PIP system was installed in a snaked configuration to achieve significant CAPEX reduction over the very few viable alternatives, such as trench and rockdump. The snakelay design pre-determines a lateral buckling response that relieves the high expansion forces in the operational pipeline, whilst controlling the level of combined loading the PIP system experiences.
The DNV 2000 Limit State design code was utilized in conjunction with the HOTPIPE Guideline to demonstrate pipeline system robustness. The HOTPIPE Guideline is not currently in the public domain, but the principles adopted therein are described in public domain papers.
This paper describes the Detailed Design process for the PIP system, and outlines the associated testing programs. The main emphasis will be given to the application of snaked lay technology, which enabled accurate pre-setting of the lateral buckle initiation sites, as evidenced by the post-operational surveys of the pipeline.
This successful application of PIP snaked lay will help bolster industry confidence at a time when the number of potential subsea applications of this technology is increasing.

Introduction

Field Description and Layout.
The Penguins field is a subsea satellite that is 66km north of its host, the Brent Charlie (Brent C) platform, in the Northern North Sea. Its location relative Scotland and Norway, is shown in Figure 1.
The cluster of four fields was developed using five subsea drilling centers (DCs). Manifolds are positioned at four of them. A single production pipeline is used to tieback the DCs in a "daisy-chain" to the BC platform, crossing two umbilicals, three operational pipelines and one decommissioned pipeline. The pipeline consists of two PIP sizes: 10.75"/16" between DC2 & DC3, and 16"/22" from DC3 to BC, via DC4 & DC5.
Figure 1 Penguin Field Location (Available in full paper)
An Overall Heat Transfer Coefficient (OHTC) of 0.7 W/m2K was specified as a target for the 66km PIP System. This was part of the flow assurance strategy for management of field shutdown and start-ups to limit temperature decay for a given shutdown period. It was also related to wax (which may become a concern towards the end of the field life) and hydrates (the formation region is approached during the last few years of production).
As well as providing electrical and hydraulic power, the 6" umbilical routed from Brent C to the subsea manifolds has provision for methanol, corrosion, scale, wax, and asphaltene inhibitors, to meet whatever needs may arise for field flow assurance.
Study of Chain Slippage for Embedded Anchors
Authors: Neubecker S.R. , O&apos;Neill M.P. 
Published: October 2008

Abstract
There are several different anchor types that rely on the point of application of the chain being below the seabed. These can include anchor piles, suction caisssons, and driven or suction installed plate anchors.
Subsequent to installation in the vertical direction, the mooring chain may be pretensioned to a nominal level in the horizontal direction, cutting through the soil to some extent. During the life of the floating installation, mooring loads will be experienced that are generally greater than the pretension level, and this brings about additional movement, or slippage, of the chain through the soil.
There are currently few guidelines in the public domain regarding the selection of a pretension level that is appropriate for any given installation. This paper will present normalised charts that allow for a quick and simple evaluation of chain slippage versus load, as a function of chain size and soil strength profile.

Introduction
It is generally accepted that drag anchors are the only types of anchor that require a specific amount of pretension on the mooring line during installation. This is to ensure that the anchor penetrates to a sufficient depth to generate the required anchoring resistance. As a consequence of having been pretensioned, the mooring system is generally proved and little additional movement or slippage of the system should result.
Conversely, pile anchors are not required to be pretensioned as they can be designed to have a sufficient factor of safety against geotechnical failure under the extreme loads once installed, and therefore movement of the anchor can be prevented.
In recent times the geotechnical efficiencies of embedding the point of attachment of the mooring line (on pile and plate anchors) have been exploited. This can occur in layered soil profiles, particularly with soft soil over hard soil, where it is beneficial to locate the anchor padeye near the strong stratum. Suction anchors installed into soft soils also typically have an embedded padeye (located about two thirds down the pile) to ensure the load is applied near the centre of resistance of the soil.
Embedment of the anchor padeye results in a situation where significant movement or slippage of the mooring line can occur in the in-place condition as environmental loads are experienced. Yet design codes do not call for a specific level of pretension to mitigate or account for this. It is generally left to the designer to determine the sensitivity of the mooring system to slippage of the mooring line (which can result in greater excursions of the vessel and overstressing of flexible risers) and to pretension the mooring line accordingly.
This paper aims to present a parametric analysis of the development of load as the mooring line cuts through the soil, enabling selection of an appropriate pretension load as a function of allowable line slippage.
Matterhorn Project
Authors: Hurel Jean-Pierre , van der Linden Cornelis 
Published: October 2008

Abstract
This paper addresses a description of the Matterhorn Project as introduction to five other more detailed technical papers on drilling, dry tree design, platform construction, SCR & pipeline design & installation for the same project
The Matterhorn Field located in Block Mississippi Canyon 243 (MC 243) was discovered in 1999 by the well EEI MC 243 #1. It is developed with a SeaStar® TLP designed and built by Atlantia Offshore Limited (Atlantia) under an EPCI Contract with TOTAL E&P USA INC. (Total). First production occurred on Nov 11, 2003, 28 months after project sanction.

Introduction
The Matterhorn Field is located in the Gulf of Mexico in Block Mississippi Canyon 243 (MC 243) by 2,816 ft of water. The block MC 243 is located about 30 miles SE of the Mouth of the Mississippi River and about 100 miles SE of New Orleans (Louisiana).
The Matterhorn field is developed with a SeaStarÂ® TLP with dry trees and it is the first dry tree TLP designed by Atlantia Offshore Limited. Total E&P USA INC. has a 100% ownership in Matterhorn.
The platform design flowrate is 33,000 BOPD and a 55 MMcfd with a field life of 20 years.
Seven future dry tree wells and one sub-sea water injection well were drilled between December 2001 and October 2002 by the dynamically-positioned semi-submersible drilling unit ENSCO 7500. Most wells are high angle, shallow kick off deviated well reaching in some case 70 deg of deviation.
The TLP has been engineered and built by Atlantia under a lump sum EPCI contract. The 84 ft diameter hull was built at Keppel FELS shipyard in Singapore while the 140 ft × 140 ft, 6,000 t deck has been built at the Gulf Marine Fabricators (GMF) yard in Ingleside (TX).
Two 16 mile pipelines (10 in and 8 in) were installed in April/May 2003 by Technip Offshore Construction, Inc. (TOCI) dynamically-positioned reel-ship Deep Blue. These pipelines are connected to the platform by 10 in and 8 in Steel Catenary Risers (SCR).
The platform is linked to the sea bottom by six 32 in tendons installed in June/July 2003. The hull and deck were installed in July/August 2003.
The 1,000 HP Nabors Offshore Corporation (Nabors) Super Sundowner XVI work-over rig has been installed on the platform using the platform cranes. This unit, after running the seven 10 in risers connecting the existing wellheads to the platform is presently performing the well completion which should last until Mid 2004.
The project was sanctioned in July 2001, the TLP was installed in August 2003 and first production was achieved on November 11, 2003.

Development Plan
Total has a 100% interest in block MC 243 in which the Matterhorn Field is located. The water Depth at the TLP location is 2, 816 ft.
The main producing sands are Plio-Pleistocene age ranging in depth from 3,000 ft to 7,500 ft below mud line. The Matterhorn Field was discovered early 1999 by the well EEI MC 243 # 1, which was drilled as an offset well to the well Conoco MC 243 #1 which discovered gas in 1990 in the deep E horizon (~10,000 ft).
Na Kika - Novel Development in Record Water Depth
Authors: Luyties W.H. , Freckelton T.P. 
Published: October 2008

Abstract
The Na Kika Development is located in record water depths in the US Gulf of Mexico. The project, a joint effort by Shell and BP, is a subsea development of five independent fields tied back to a centrally located host facility. The subsea infrastructure consists of 10 wells connected via three 25-mile flowline loops, 23 flowline sleds, and 50 miles of umbilicals to the semi-submersible shaped host with topsides facilities for fluid processing and pipelines for oil and gas export to shore. A sixth field will be tied back in 2004, and the host and subsea infrastructure is designed and built for other tiebacks to enablefurther development in the area.
This novel co-development is the result of an 18-year effort to discover sufficient reserves to support a development, understand the complex geology of the area, identify an economical development system, and design, construct, and install the system. In addition to the usual issues surrounding a $1.4B development, Na Kika faced and overcame numerous other execution challenges, including aggressive cost and schedule targets, application of new technology, regulatory issues, HSE management, a difficult contracting climate, and a protracted installation campaign during an active hurricane season. As a final challenge, the Na Kika Joint Operating Agreement required a transfer of Operatorship from Shell (Development Operator) to BP (Production Operator) upon production of the first well.
First production from Na Kika was achieved on November 26, 2003.

Novel Co-Development
The Na Kika Development is located approximately 140 miles southeast of New Orleans in water depths ranging from 5,800' to 7,000 feet. The project is a subsea development of five independent fields - Kepler, Ariel, Fourier, Herschel, and E. Anstey - tied back to a centrally-located, permanently-moored floating development and production host facility situated on Mississippi Canyon Block 474. Shell E&P Americas (Shell) and BP are joint owners (approximately 50% each) of the five primary Na Kika fields. The Kepler, Ariel, and Herschel fields are predominately oil while Fourier and East Anstey are predominately gas.
A sixth field, Coulomb, a gas field owned by Shell and Petrobras, is in a water depth of approximately 7,600' and will be tied back to the host facility as well.
The five Na Kika fields can be considered small to medium sized ranging in size from 20 to 100 MMboe, with the largest being the Kepler field. None of the fields on its own could be developed economically with the technology available today. In fact, the total recoverable hydrocarbons from the Na Kika development are approximately 300 MMboe. Although this, in total, is a reasonable amount of hydrocarbons for a development in the deepwater Gulf of Mexico, given the complexity of a multi-field subsea development in record water depth, Na Kika can be considered a marginal development. For detailed information on the Na Kika subsurface, see Ref. 1 (OTC 16699).