bluuebunny/crossref_metadata_2025 huggingface dataset:
The Girassol Development: Project Challenges
Authors: Serceau A. , Pelleau R.
Published: October 2008

The Girassol field, offshore Angola, is the largest deepwater subsea development ever brought into production.

This development has been marked by three key dates: discovery (April 1996), sanction (July 1998) and first oil (December 2001).

This paper gives a general description of the Girassol development, outlines the main challenges faced during the project phase and introduces the other papers which are presented on Girassol.

Introduction

The Girassol Field is located 210km northwest of Luanda, the Angolan capital, and about 150km from shore (Fig 1 - Field location).

Girassol was the first discovery made in the prolific Block 17. This was followed by Dalia, Rosa, Lirio, Jasmim, Cravo, Orchidea, etc. The project 's chronology has been marked by three significant dates:

April 1996: Girassol field is discovered on Block 17in deep waters, offshore Angola. This is the first major oil discovery by a consortium led by TotalFinaElf E&P Angola (40%, operator) and its partners - ExxonMobil (20%), BP (16.7%), Statoil (13.3%) and Norsk Hydro (10%). The Block 17 Production Sharing Agreement was signed at the end of 1992 with Sonangol, the Angolan state oil company.

July 1998: The Girassol development project is approved by all parties

December 2001: Less than three and a half years after approval, Girassol comes onstream. By the end of 2001, daily production is 100,000b/d with the production plateau of 200,000b/d to be reached by April 2002.

Girassol is a deepwater giant by many standards:The reservoir, located in 1,400m water depth, is large (10km by 14km). Estimated oil in place is 1,550mmbbls with recoverable reserves put at 725mmbbls. The oil quality of 32°API is close to Brent specifications. Main reservoir and fluid characteristics are given in Fig 2.The Girassol development scheme is based on 39 subsea wells - 23 oil producers, 14 water injectors and two gas injectors. The field will be developed in two phases: the first phase, completed in December 2001, includes 11 wells - eight oil producers, two water injectors and one gas injector. The second phase development is ongoing and will be completed mid-2003 (Fig 3: Field development scheme).The overall investment for the two phases of the Girassol development is US$2.8bn.

In order to bring such a large field onstream in deep waters, it has been necessary to develop and qualify new equipment and to address a number of key issues, such as flow assurance, the need for a flexible subsea layout and reservoir uncertainties.

The Girassol project team had to fulfill three main objectives:First priority was given to technical quality. An extensive qualification program had to be carried out and offshore procedures had to be tested in both shallow water and deepwater tests.Second priority was to closely monitor the development budget and contain the final cost.Third priority was to achieve first oil as early as possible. A very demanding schedule was defined at project sanction with a target start-up date of the end of 2000.

The first and second objectives have been met.
Girassol - The Umbilicals and Flowlines - Presentation and challenges
Authors: Rouillon Jacky
Published: October 2008

The Girassol field development, offshore Angola in 1,400m of water, has stringent operating requirements due to flow assurance issues and the need for flexibility. The result was the selection of new riser and flowline concepts with numerous qualifications for materials and equipment. This paper details how these concepts - freestanding riser towers, insulated flowline bundles and a mid-depth export system - met project requirements.

UFL has demonstrated that solutions could be developed in a short timeframe. These concepts will be used as a reference for other deepwater developments and while alternative solutions may be chosen, the challenges will be similar.

UFL system presentation

The umbilical and flowline network, part of the Girassol development, is made up of the following main systems:

Production system

The production system comprises five production loops. Thirteen manifolds are installed in 'daisy chains' along these loops. Up to two production wells can be tied in to each manifold.

Each of the production loops is made up of two sections: the production bundle on the seabed bottom and the production riser integrated within the riser towers connected to the FPSO.

Production bundles

Each of the five production loops consists of several production bundles interconnecting the manifolds (refer to the overall field layout).

In total there will be 11 production bundles with eight installed during the first phae of the offshore operations carried out during 2001.

Each production bundle contains (Fig.5):Two by 8in production flowlines.One by 2in service line.These lines are contained within two semi cylindrical modules of syntactic buoyancy foam, which ensure the thermal insulation of the pipes.One by 30in carrier pipe housing the insulation foam, the production and service lines.

The carrier pipe ensures the mechanical protection, the corrosion protection and contributes to the overall thermal performance of the system as it avoids exchanges of seawater with the external environment. The carrier pipe is entirely closed and full of inhibited water.

The weight in air is 550kg/m with a submerged weight in production condition is in the range of 90kg/m. Each bundle is equipped at each end with a sled (Fig. 6), which is used for the installation by seabottom tow and also as structural support to perform the tie-in of the spools connecting the bundles to the manifolds.

The length of the production bundles varies from 700m to 3,000m. The lengths have been determined on the basis of the subsea field layout, but are limited by the bollard pull of the towing spread used for installation.

Production risers

The 8in and 2in risers, which are a continuation of the pipelines in the production bundles, are integrated within freestanding riser towers (Fig. 1 and 3).

Each production riser is equipped with a 3in gas lift line with an entry point at the bottom of the riser tower.
Development of the Prince Field
Authors: Koon J.R. , Heijermans Bart , Wybro P.G.
Published: October 2008

This paper covers the development of the Prince (formerly known as Sunday Silence) Field. The paper outlines how the lease operator and owners in conjunction with turnkey contractors succeeded in developing a relatively small oil field (in deepwater terms) in an environment of low oil prices. This work included the first application of the "MOSES" Tension Leg Platform. The "MOSES" TLP is the first of a new 4th generation in TLP designs that introduces a new hull configuration offering the industry improved platform motions, lower cost, and less fabrication time than other deepwater platform concepts. The successful completion of the development of the Prince Field proves that the industry can execute innovative deepwater development projects on a lump sum contract basis in record setting time frames without costly overruns.

Introduction

The Prince Field is an oil discovery with associated gas located in Ewing Bank Block 958, 959, and 1003, 80 miles offshore Louisiana in a water depth of 1490 ft. (Reference Figure 1) The three leases are unitized in the Ewing Bank Block 1003 Unit. The Prince Field was developed by means of four (4) predrilled wells that were completed and tied back via top tensioned risers to dry trees located on a MOSES TLP. Oil and associated gas are processed to pipeline specifications on the platform and exported via two (2) export steel catenary risers (SCR). The pipelines and SCR's were pre-laid in April 2001, and the TLP was installed in July 2001. The first riser was installed and the initial well was brought on-stream in September 2001.

The development of the Prince Field can be characterized by the following industry trendsetting activities:The Prince Field was the first deepwater field that received royalty relief under the Deepwater Royalty Relief Outer Continental Royalty Relief Act.A MOSES TLP was selected for the Prince Field development after four competitive bids had been reviewed. This marked the first time in the Gulf of Mexico that competitive bidding was used for a turnkey deepwater floating platform concept selection and the first time that the MOSES TLP was selected.The SCR's designed for the Prince Field development are the world's shallowest SCRs suspended from a floating platform. Additional details are provided in the paper listed in the reference section 1.The Prince Field development marks the first time that the working interest owner in the leases (El Paso Production GOM, Inc.) decided to contract with a pipeline and platform infrastructure company (El Paso Energy Partners, L.P.) to have El Paso Energy Partners own and operate the deepwater platform and process production from the field for a fee. This arrangement lowered the development costs and made it possible for El Paso Production GOM, Inc. to develop the field with a deepwater platform in lieu of a subsea tie-back.The TLP hull is the first use of a new 4th generation TLP design that offers the industry a new alternative with dry tree or wet tree capability.
Composite Risers and Tethers: The Future for Deep Water TLPs
Authors: Botker Stig , Johannessen Thomas B.
Published: October 2008

The present paper describes the extension of well proven TLP technology to applications in ultra deep waters. It is concluded that the careful optimisation of the TLP hull and topside as well as the use of composite risers and tethers lead to economical and technically feasible TLP solutions at water depths as large as 3000 m.

The paper addresses the following subjects:TLP technology and hydrodynamic optimizationComposite risers and tethers impact on overall TLP designComposite riser and tether design and fabricationStatus on the composite tether and riser development program which is ongoing through the Conoco/Kvaerner Composite AllianceMInstallation of composite tethersA case study including cost estimates

Introduction

The TLP concept has proven to be suitable in both harsh and benign climate conditions during the last two decades. TLPs have been chosen at water depths down to approximately 1300 m. However, for water depths larger than this, the weight of conventional tether and riser systems becomes large and begins to dominate the entire global configuration of the TLP. This may result in a solution which is not feasible either from an economical or a technical point of view.

Alternative floating dry completion units have recently been introduced for large water depths. In particular the Spar buoy concept has been successful in the Gulf of Mexico. The alternative solutions are, however, technically challenging, typically involving large relative motion between the dry wellheads and the floater as well as significant offshore work prior to installation.

In 1995, Kvaerner and Conoco established a Composite Alliance with the aim of exploring the business potential of composite solutions in the offshore and shipbuilding industries. It was concluded in a holistic study that the largest potential lies in the development of composite risers and tethers. As a result, two large development programmes were initiated, namely the CompRiser programme initiated in 1996, and the CompTether programme initiated in 1998. The main objective of the two programmes is to qualify the technology by prototype testing and offshore demonstration.

The application of composite tethers and risers go a long way in resolving the main concerns of employing TLPs for deep water applications. This fact, together with the excellent track record of the TLP and the prospects for new deep water field developments, led to the initiation of a development project within Kvaerner Oil & Gas (KOGAS) in 1999. The main objective was to improve the economy of TLP solutions and to extend the water depth range for economical and technically feasible TLP solutions down to 3000 m both for harsh and benign environments.

This goal was achieved by bringing in new ideas for the overall configuration, construction and installation of the TLP, and by using composite materials for the fabrication of tethers and risers. The present paper summarises the main conclusions from this development project and the composite development projects.
Maureen Refloat Project: Challenges to Control Weight and Stability Through a Decommissioning Project
Authors: Røed Kristian , Karlsen Kristin , Davies Richard
Published: October 2008

This paper gives a brief summary of the methods, actions and decisions involved in maintaining control of Maureen Alpha's weight, centre of gravity and hydrostatic stability through the decommissioning process.

The process described herein is an example on "backwards" engineering, retracing a structure's history and deciding how to handle the information, rather than adapting a design to given parameters and constraints.

Introduction

On June 26th 2001, eighteen years after its installation, the 110 000- tonne Maureen Alpha steel gravity platform was refloated in UK waters, and the three-days tow towards Stord, Norway initiated. Maureen, which was owned by Phillips Petroleum Co UK, had been the largest offshore steel platform in the North Sea. Aker Maritime was awarded the contract for removal of the platform in 1999.

Accurate weight data were essential in the calculation of the platform's floating stability, which was a highly critical factor during the ascent from the seabed to floating condition with very little water plane area.

This paper will cover the approaches to the following challenges encountered in the weight and stability analyses:The accuracy and reliability of the 18-year old as-built and as-installed documentation.Weight and buoyancy changes during platform service time. Scanning of lifting logs and the search for undocumented changes.Production system residues. Definition of the weight of remaining mud, scale and liquid. How thorough is the cleaning of the pipes and tanks?

Undocumented changes to the substructure:Weight and nature of marine growth on the structure.Water inside the lattice frame. Sluiced in upon installation, how to evacuate the structure before refloat, and how to cope with remaining water volumes.How to account for wax and residues in the storage tanks.Sacrificial anodes. How much is left?Breached lattice members. Full, half full or still dry?Stairs, ladders and walkways under deck partially destroyed by waves.The application of "allowance for uncertainty". A considerable amount of weight and stability contributing items were indefinable and had to be accounted for by means of statistics. Assuming worstcase scenarios would never have allowed the re-float operation to take place.Stability criteria. DNV rules define the operation as a "transient phase", hence applicable stability criteria had to be defined by the Main Contractor, based on weather limitations, maximum inclination limits and the decision that clashes with seabed structures were to be avoided.

More detailed descriptions of the Maureen platform and the history and particulars of the re-float project in general, can be found in /1/.

All units referred to in the text are SI standard metric units.

Reference systems

Given a set of data where virtually every figure is subject to doubt with variable levels of influence on the total, the first task is to define some fixed reference to hang all obtained results on.
Design Criteria and Inspection Strategy for FPSO's
Authors: François Michel , Frorup Ulrik
Published: October 2008

The FPSO's now under operation or construction are mainly ship-shaped structures. However these units differ significantly from oil trading tankers for their service conditions, being in continuous operation at sea and Site specific as opposed to ocean trading. Therefore, Classification Rules for FPSO's are providing complement, and provide the necessary input, before application of the Ship Rules that are the standard reference for shipyards.

A FPSO is constantly in loading/unloading process and loading conditions have to be carefully studied, taking into account both operating requirements, and future maintenance and inspection requirements.

As a FPSO is a site specific unit, study of the loads induced by waves is to be performed, and comparison of the results with the standard requirements for trading ship will provide the data required for the application of (ship) Class Rules.

Given Operator's objectives of a vessel in continuous operation at sea, and no dry-docking for the intended service life, durability is an essential consideration, with implication on design for e.g. accessibility, corrosion protection and corrosion margins, and Fatigue strength.

Tools are available, at the design stage, to perform strength and fatigue evaluations of the structure, and help in design. The database thus obtained will provide, during vessel operation, a compliance management tool for the hull structure.

Issues in this paper are discussed based on the experience gained in new-built but also converted FPSO's actually moored in various areas of the globe like West Africa, China and Brazil.

Introduction

The FPSO's (Floating Production Storage and Offloading Units) now under operation or construction worldwide are mainly ship-shaped structures purpose-built or converted by shipyards based on their know-how and application of Classification Societies Rules.

The Classification Societies were established during the 19th century with the development of the shipping industry, to provide independent information on the actual condition of the ships, and to develop Rules for Classification of Ships including design, construction and maintenance/surveys requirements.

With the development of international conventions, Flag states have recognized their competence and technical expertise and have often delegated their technical inspections to them.

This has helped Classification Societies to harvest and compile unrivalled knowledge in terms of ocean-going structures and safety at sea. Then, the development of an expertise in offshore installations was considered as a natural extension of their duty of encouraging the protection of life and environment at sea.
Global Performance of Floating Production Systems
Authors: Garrett D.L. , Chappell J.F. , Gordon R.B.
Published: October 2008

Fully coupled global analysis of Floating Production Systems, including the vessel, mooring and risers is described. Modeling procedures for each component, including hydrodynamic modeling, characterization of the environment and element length selection for mooring lines and risers, are presented. Simulation requirements for both Frequency Domain and Time Domain analysis are presented. This includes criteria for selection of frequency content and simulation length.

Results for two Floating Production Systems are presented. The first is a Gulf of Mexico spar with taut-leg mooring and top-tensioned risers in a water depth of 6,000 ft. The second is a spread moored West Africa FPSO with steel catenary risers in 4,500 ft water depth. Modeling of each is described. Results for vessel motions, riser stresses, and mooring line tensions are presented, including detailed comparisons of Time Domain and Frequency Domain results.

INTRODUCTION

Development of deepwater fields requires complex systems for production and export of oil and gas. These can include combinations of steel catenary risers, flexible flowlines, top tensioned risers, and hybrid risers, connected to one or more moored floating structures ("floaters") such as spars, TLPs, semisubmersibles, and ships. The floater may be moored with either catenary or taut legs.

Coupled analysis includes detailed models of the floater, the mooring lines and the risers in a single model. A single model can include a floater, 12-16 mooring lines and 20 or more risers, resulting in models with more than 10,000 degrees of freedom. Stochastic analysis is used to calculate the response to wind, wave and current loads. For fatigue analysis, there may be more than 1,000 load cases. Efficient, accurate modeling is needed to produce the results needed for design.

Recommendations for developing efficient, accurate models for both Time Domain and Frequency Domain analysis are presented. The criteria have been developed over many years of modeling and analysis of Floating Production Systems.

COUPLED ANALYSIS METHODOLOGY

The coupled analysis for the examples was performed using Stress Engineering Services' RAMS (Rational Approach to Marine Systems) software. The modeling criteria are not restricted to RAMS, but are generally applicable.

RAMS uses a consistent cubic finite element representation of an elastic rod [1] to model risers, TLP tethers and mooring lines. The element includes axial and bending stiffness. Bending stiffness varies linearly and tension varies quadratically along the axis of the rod. The external load model accounts for weight, buoyancy, internal fluids and hydrodynamic loads. A generalized Morison model is used to compute hydrodynamic loads. Seabed contact is simulated by nonlinear spring and friction models. The finite element method uses a displacement formulation that allows for large element displacements and rotations in three-dimensional space, while strains are assumed to be moderate.
Environment Severity Factors and Their Applications in FPSO Hull Strength Assessment
Authors: Zhao Chuntian , Wu Jer-Fang , Huang Ken , Shin Yung
Published: October 2008

This paper presents an approach to conduct the scantling design and strength assessment for a ship-shaped FPSO to be stationed at a specific site. By introducing the Environment Severity Factors (ESFs), the effects of the site-specific wave conditions and the mooring/risers as well as the topsidestructures on the loads of FPSO hull structure can be considered while the strength analyses and criteria can be kept as simple as those used in the design of ocean-going tankers. The determination of ESFs is based on the direct calculation of wave-induced and motion-induced loads. The determinations and applications of ESFs for two common types of wave conditions are discussed, in which:wave conditions can be represented by a wave spectrum of simple-form or by the long-term wave scatter diagram consisting of wave spectra of simple-form, such as JONSWAP wave spectrum andBretschneider wave spectrum.Wave conditions cannot be represented by a wave spectrum of simple-form, for example, for the cases that both seas (wind or storm generated waves)and swells exist.

The latter becomes more complicated if the seas and swells propagate in different directions, which may occur in some offshore areas such as offshore Brazil and West of Africa. For the design and analysis of an FPSO conversion, the ESF concepts can also be used in assessing the fatigue damage accumulated during the past route services as an ocean-going tanker. The proposed approach for the strengthassessments can be applied to both the newly built and the converted FPSOs. This approach can facilitate the hull scantling design and strength assessment.

Introduction

A Floating Production, Storage and Offloading system (FPSO) is a popular type of vessel used in the offshore oil production. An FPSO may be a newbuild or a conversion from an oil tanker, which has been in service for some years. The discussion of the proposed approach covers both types of FPSOs.

In general, FPSO design is more complicated and time consuming than tanker design for the following reasons:FPSO design requires the application of site-specific environmental conditions, while tanker design applies unrestricted-service wave conditions, which are rule-based for all ocean-going tankers. The rule-based design is generally much simpler than the case-by-case design. Besides, FPSO design also needs to consider the specific transit and installation conditions.FPSO design criteria will not be the same as those for tankers. For example, tanker design uses 20-year extreme wave conditions, while FPSO design uses 100-year waves.FPSOs have more complicated structural configurations. The effects of mooring/riser system and topside structures need to be considered in the FPSO hull design. Due to the interaction of these design considerations, the hull structure design may need to go through several iterations.
Evaluation of Drilling and Completion Techniques Used In 10 Years of the Deepwater Marlim Field Development
Authors: Juiniti Ricardo
Published: October 2008

Marlim field, discovered in December 84, with a total area of 132 square Km lays in water depths from 650 to 1,050 meters. First oil came on stream in 1991 with the vertical well 3 MRL 3 RJS at 721 meters of water, after the development of guidelineless subsea hardware as well as other technologies to allow production in deepwater.

The main idea, still in use these days, was to develop the field with simple drilling and completion projects. The water depth, highly friable sandstone and high costs in deepwater drilling and completion were some of the obstacles to be overcome.

During the field development, the better knowledge of the reservoir, as well as other innovative drilling and completion techniques in deepwater, allowed a higher production of the wells.

A total of 129-production and water injection wells either vertical, directional or horizontal will be on stream in Marlim and many lessons were learned along the last ten years. The best practices for drilling and completion were implemented not only in Marlim but also in other offshore developments in Brazil.

This paper will present the drilling and completion techniques used in Marlim field development and show how these techniques contributed for the production increase.

Although the field development is close to the end, new well designs are being studied to be implemented thus confirming the importance of Marlim field as the most important laboratory for deep and ultradeep water development. Moreover future challenges for workovers will be anticipated.

Introduction

Deepwater drilling offshore Brazil started in 1984 when a conventionally moored drillship drilled the well 1 RJS 287 at 501 meters water depth (WD). In the same year, the first dynamic positioning (DP) drillship contracted by Petrobras also started an exploratory campaign in Campos Basin.

The first well drilled by this DP drillship, the 1 RJS 219 A at 853 meters of water stroke oil in December 84. The tests performed in February 85 showed an unconsolidated sandstone reservoir with permeability of 2 Darcies and high gravity oil (ranging between 17-21 API).

Further drilling and appraisal activities confirmed a total area of 132 square Km with oil in place of 9.0 billion barrels. An appropriate name then was given to this discovered giant field: Marlim. (Fig 1)

Other fields named Marlim Sul, Marlim Leste and Voador fields were also discovered during the delimitation period of Marlim field.

The productivity index (PI) of these wells reached up to 300 m3/day/kgf/cm2 and sand production demanded adequate control mechanisms.

By 1989, ten wells had been drilled in the Marlim Complex and the main problems to drill wells in deepwater were being surpassed year after year, but production at such water depth was still challenging.

Several alternatives to exploit Marlim field were analyzed but all of them impaired restrictions.
A Deep Draft Semisubmersible with a Retractable Heave Plate
Authors: Halkyard J. , Chao J. , Abbott P. , Dagleish J. , Banon H. , Thiagarajan K.
Published: October 2008

Gulf of Mexico deep water oil fields present challenges to the offshore industry. Large fields require heavy drilling and production topsides which favor inshore deck installation, hook-up and commissioning in order to reduce time, costs and risks associated with carrying out such operations offshore. Harsh environments require that the motions of the structure be small to allow the use of dry trees and SCRs. A new system, called the DPS 2001, has been developed, which is a deep draft semisubmersible with a retractable heave plate. The system combines the advantages of a semisubmersible with the operational motion advantages of a truss spartype floater. Minimal motions of the DPS 2001 allow the use of dry trees with drilling/workover capability. The truss/heave plate is in a retracted configuration during fabrication and towing; this allows the deck to be stalled and commissioned inshore. The truss/heave plate is lowered and locked at a deep draft after the DPS 2001 is towed to the installation site. Because of the heave plate, the DPS 2001's motions are significantly less than that of conventional semisubmersibles and ship-type hulls.

INTRODUCTION

The DPS 200101 is a floating drilling and production platform designed specifically for oil and gas development in deep water harsh environments. Three different versions of the DPS 2001system are currently being developed by CSO Aker:DPS 2001-4: a fourcolumn version of the system for 8,000 - 10,000 st topsides,DPS 2001-3: a three-column version of the system for 5,000 - 8,000 st topsides, andDPS 2001-5: a five-column version of the system for use with a topsides up to 40,000 st.

A patent is pending for the DPS 2001. The DPS 2001-5was presented at the 2001 DOT conference. The DPS 2001-3will be presented in the near future. The DPS 2001-4is the focus of the present paper. The DPS 2001-4is shown in Fig 1. The upper hull consists of horizontal pontoons and four corner columns and provides buoyancy. The lower hull consists of a heave plate and a truss that supports the heave plate. The heave plate provides large added mass and significantly reduces the platform's motions. The DPS 2001-4is anchored to the sea bottom with a spread mooring system consisting of chains, steel strand or polyester ropes and suction anchors.

The upper hull is similar to a typical semisubmersible hull. The lower truss and heave plate unit is similar to the truss structure employed on truss spars. The system is an integration of proven components and embodies the best features of both a semisubmersible and a truss spar.

The hull and the truss/heave plate unit can be fabricated in a number of yards in Asia or Europe. Upon completing the hull and truss/heave plate, it will be drytransported to the GOM. The hull and truss/heave plate will be in a retracted configuration during fabrication and transportation (Fig 2).
Prediction of the Holding Capacity and Trajectory of Drag Embedment Anchors
Authors: Ruinen Roderick , Degenkamp Gijs
Published: October 2008

The authors have presented a summary of the various methods that are available to determine the holding capacity and trajectory of drag embedment anchors. One of the drawbacks of the methods that are available today is that these are generally only suited for a single type of soil. The authors are currently working on a methodology that will predict the performance of anchors in varying soil conditions. The initial findings and the methodology are presented.

Introduction

Drag embedment anchors are a common method of fixing floating structures to the seabed. Over the years numerous methods have been developed to determine the holding capacity and trajectory of the anchor in the seabed. The most common of these, are the design graphs developed by the various anchor manufacturers. More recent developments are the development of methods which can predict the anchor holding capacity and trajectory based on geotechnical methods.

The prediction of the anchor holding capacity and trajectory can be split into a number of distinct parts, being:The static holding capacity of an anchor penetrated to a certain depth into the seabed, both in cohesive and cohesionless soils.The profile that the mooring line makes in the seabed (the inverse catenary).The kinematic behavior of the anchor and mooring line in the seabed.

To accurately predict the anchor performance, these 3 parts should be combined into a single methodology.

This paper will discuss the various methods that are available to determine the performance of the drag embedment anchor. The design graphs, static holding capacity, mooring line profile and anchor kinematics will be presented in details showing the various methods that have been developed. The final part of the paper will discuss a method that the authors are working on, which in their opinion gives an accurate method of predicting the anchor performance. While the authors have tried to give a complete view of the material that is available, they do not claim that the material presented in this paper is complete.

Design graphs

The most common method of predicting the holding capacity of drag embedment anchors is the use of design graphs. Typically these graphs are shown on double logarithmic scale, with the weight of the anchor on the horizontal axis and the holding capacity of the anchor on the vertical axis. Holding capacity curves are generally presented for sands and soft clays.

The basis of these design graphs for a specific anchor type is the tests performed with a number of small scale anchors (typically up to a weight of 3 metric tons) which have been tested up to the ultimate holding capacity. The ultimate holding capacity being defined as the maximum horizontal steady pull which can be resisted by the anchor at continuous drag. Based on the tests with the small scale anchors, the performance of the larger size anchors has been extrapolated. These design graphs are supplied by the various anchor manufacturers for their specific anchors.
Expandable Liner Hangers: Case Histories
Authors: Moore Melvin J. , Campo Donald B. , Hockaday Joel , Ring Lev
Published: October 2008

Initial liner top integrity is a primary concern for most operators. If the liner top fails routine or regulatory integrity tests, expensive and time-consuming remedial operations increase direct costs for equipment and services. This remediation delays well completion, which ultimately delays revenue generation. These expenses often exceed the initial cost of the liner equipment. Liner top failure continues to challenge the industry despite improvements in integrally run liner top packers, special cements, and cementing pratices. Even newer generation liner top packers, run either integrally with the liner hanger or as a second trip packer, have multiple sealing surfaces that must function under rigorous conditions to achieve liner top isolation.

The expandable liner hanger has been developed and successfully field-tested as an alternative to conventional "cone and slip" liner hangers and liner top isolation packer systems. The expandable liner hanger combines the functions of the liner hanger and the isolation packer into a single component. The expandable liner hanger uses elastomeric "bands" to provide the axial load capacity of a conventional liner hanger and the annular sealing capability of the liner top isolation packer. The expandable liner hanger is expanded hydraulically with the liner running/setting tool assembly. During expansion, the elastomeric bands are compressed into contact with the ID of the supporting/intermediate casing, virtually eliminating the annular space between the liner hanger and the casing.

This paper discusses expandable liner hanger design criteria and testing undertaken to qualify the expandable liner hanger as a reliable liner top isolation system. Initial field installations and the lessons learned are also discussed.

Introduction

The importance of the liner-casing overlap is illustrated by the efforts and expense taken by operators to ensure hydraulic integrity of the overlap. Typical methods of achieving pressure integrity include the following:Cement "squeezes," including a liner top packer as a component of the initial liner hanger settingOne or more "second-trip" liner top isolation packers installed to control gas migration at the liner top

The typical liner top is complex in its design (Fig. 1) and can develop leaks due to a myriad of causes1.

A recent informal survey of several GOM operators revealed that 30 to 50% of pressure seals in overlaps fail. One operator made a concerted effort to improve liner running and cementing procedures. Data gathered over an 18-month period was used to shed light on possible causes of overlap failure by gathering information on liner/casing sizes, types of equipment, overlap length, mud data, annular cross section, equipment, and service suppliers. The study concluded the chances of having a liner overlap seal failure did not depend on any single factor and the chances for an incident were nearly the same regardless of the factors associated with any given well2.
Ferro-Cement as a Material for Offshore structures
Authors: Shah S.P. , Key W.H.
Published: October 2008

To facilitate rational design in this relatively new material, influence of matrix composition and wire mesh properties on static and dynamic strengths of ferro-cement specimens were studied. The possibility of increasing strength-to-weight ratio by substituting foamed lightweight sand for natural sand was also. investigated. Ductility of steel and specific surface of wire mesh appear to be the most important properties influencing cracking behavior and hence the leakage rate. Results suggest that ferro-cement may be a potential material for construction of thin shells such as for boat hulls, of containers for transportation of LNG, and of deep submersibles.

INTRODUCTION

Ferro-cement is a type of reinforced concrete in which the matrix is portland cement mortar and the reinforcement consists primarily of layers of steel wire mesh. Woven or welded cold drawn wire mesh, having a grid from ¼ to 1 in. and wire diameter from 0.02 to 0.06 in., is commonly used. Presently, the most prevalent use of ferro-cement construction is for ½ to 1½ in. thick shells for boat hulls. The most common construction technique for boat hulls employs bent pipes and. rods to define the shape of the hull. Wire meshes are laid over the framework and the mortar is plastered on from both sides.

Ferro-cement has become an increasingly popular building material for boats ever since Nervi in Italy, shortly after World War II, built a 41-ft × 10.5-ft × ½ in. sailing yacht. Since then, ferro-cement boats have spread progressively to England, Australia, New Zealand, Canada and the U. S. Although most of the boats built in these countries are not larger than 80 ft, larger and more varied types of ferro-cement shipping vessels have been built in Russia and Czechoslavakia.

In spite of the increasing interest in ferro-cement, information on which a rational design can be based and from which a suitable comparison with other materials can be made is not available. The purpose of this research was to investigate the impact resistance of ferro-cement plates since impact loading would be critical for many applications of ferrocement in offshore structures. Behavior under uniaxial tension was also studied and related to the performance under impact. The influence of different mortar compositions and yield strength of mesh, as well as changing surface areas of reinforcement were explored. Measurements of crack width and of leakage rate of damaged material were made. It is hoped that information provided here may lead to better utilization and evaluation of ferro-cement for offshore structures such as shipping vessels, buoys, deep submersibles and vessels for transportation of liquid gases.
Dynamic Response Of Offshore Piling
Authors: Ross Hayes E.
Published: October 2008

To perform dynamic analysis of pile supported offshore structures, the manner in which the individual piles interact with the wave and the soil should be understood. A mathematical model was developed to study this dynamic interaction taking into account nonlinear soil resistance properties and geometrical nonlinearity of the pile. The model also provides a means of studying the effects of permanent set in the soil which may occur as the pile oscillates. The effects of selected parameters on the response of a typical pile are analyzed and discussed. In addition to advancing the state-of-the-art in design and analysis 'of offshore structures, the model can also be used to analyze the dynamic response of a marine riser.

Introduction

Many offshore structures are supported by piles driven into the bed of the ocean. Frequently, the critical factor in the design of these structures is the lateral dynamic loading from waves. Knowledge of the interaction between the pile and its water and soil environment is a requisite to accurately compute the response of a pile-supported offshore structure. The research described herein attempted to fill this need by developing an analytical means of predicting the dynamic response of offshore piling.

Although this study was primarily concerned with offshore piling, it will have applications in other areas. For example, the marine riser on an offshore drilling platform, which is subjected to wave action between the platform and the bed of the sea, can be analyzed by this method. A floating rig which extracts core samples or drills for oil may operate in water of considerable depth and its riser may experience high dynamic loads.

To date, considerable effort has been expended in the field of soil-structure interaction, particularly under static loads, and in some cases under dynamic loads. In laterally loaded pile studies the usual approach to the problem has been through experimental analysis, by either prototype or model. Economically, experimental analysis is often undesirable. Another undesirable feature is that the results are usually applicable to only the type of piles tested.

In most analytical studies found in the literature, inherent assumptions usually limit their results to special cases in which the soil and pile behave as linear elastic systems. For some applications, these assumptions may lead to relatively accurate results, while in others they may result in completely erroneous conclusions. At present the uncertainty remains, especially in dynamic analysis.

Since there was a marked absence of information on the dynamic behavior of laterally loaded offshore piling, the primary reason for conducting this study was to advance the state-of-the-art.
DeepStar 10,000-ft Water Depth DDCV Study
Authors: Bhat Shankar U. , Greiner William L. , Barton Dave
Published: October 2008

Deep Draft Caisson Vessels (DDCV) or spars have been used in the Gulf of Mexico in water depths up to 4,800 ft and their use is being considered in ultra-deep waters up to 10,000 ft. A major study sponsored by DeepStar was used to provide a systematic and credible evaluation of DDCV mooring and riser technology alternatives for a challenging 10,000 ft water depth application in the Gulf of Mexico. This paper provides an overview of the DeepStar study objectives, scope and the significant conclusions. A base case DDCV was first developed for 10,000 ft water depth using extensions of current technologies for hull, mooring and risers. Several cost saving alternatives were then considered. These included polyester mooring, composite risers and a high level evaluation of other lightweight risers. A high pressure and high temperature reservoir and a high current environment (HP-HT-HC) were considered. The comprehensive study resulted in a number of significant conclusions.

Introduction

This paper provides an overview of a major study carried out in DeepStar Phase V (Ref. 1). The primary objectives of the study were to assess credible technology alternatives for mooring and top-tensioned production risers (TTRs) for a large ultra-deepwater DDCV, and to quantify the total system incentives for pursuing synthetic moorings and composite production risers.

In addition to the primary scope described above, the study team was also asked to seek industry input and to provide a preliminary assessment of other potential alternate lightweight risers.

The six month study was initiated in October 2001, with Halliburton KBR as the primary contractor. ExxonMobil was the oil company champion and the manager of this study within DeepStar. DeepStar is a research and development consortium of 15 oil and gas companies and about 50 service companies (see www.deepstar.org).

The design basis chosen for the study included the following challenges:A high pressure high temperature fieldA very high current environmentLarge topsides of 40,000 short tons operating weightA significant number of steel catenary risers (13 SCRs and 5 umbilicals).20 top tensioned risers (TTRs). The scope of the study included consideration of several configuration cases listed in Table 1. The initially agreed scope included cases 1, 2 and 3. Cases 1A, 1B, 2A and 3A were added subsequently as the study developed. The scope of the study was comprehensive, including:DDCV hull sizingMooring designGlobal performance calculationsMooring fatigue analysisRiser configuration designProduction/drilling riser clearance assessmentProduction riser strength and fatigue calculationsHull scantling checksHull fabrication, transportation and installation methodsMooring installationCost and schedule estimatesConsideration of other lightweight riser materials Mooring design and mooring fatigue analysis were performed for both steel and polyester mooring systems. Riser clearance and strength, including fatigue, were analyzed for both steel and composite risers.
Monitoring of Offshore Pipes
Authors: Binet Eric , Tuset Paal , Mjøen Stig
Published: October 2008

The lifetime of offshore field developments can be as long as 20 to 30 years. Operators must have continuous focus on their assets throughout the field life. The monitoring of the operational data is therefore a key issue to assess integrity and to ensure a safe and optimal operation of the flexible risers. In co-operation with CorrOcean ASA, Technip-Coflexip has established a Pipe Integrity Management (PIM) system where relevant operational data, monitoring and inspection results are gathered into a database, treated and analyzed.

This paper describes the PIM system recently implemented for Statoil ASA on the Åsgard field (North Sea). We present the database principle and the most relevant operational parameters monitored in operation. The findings of the operational data review are then discussed and compared with risers original design assumptions. Finally the paper presents the benefits to Operator of such a system.

Introduction

Most Operators operate flexible pipes without a dedicated system to follow up the integrity of the flexible pipes. Hence, any evaluation or assessment of the pipe conditions requires substantial collection of original design data, manufacturing data and not least operational data. Experience has shown than the gathering of relevant operational data can be difficult already after some years in service. In addition, especially for long field life (15 to 20 years), the operational conditions may sometimes differ compared to assumed original design basis data. Without a good knowledge of the operational riser history, the flexible riser integrity assessment can become a difficult exercise, leading for example to either operational limitations or even riser change-out, which could have been avoided or delayed if good monitoring data had been available.

Statoil's Åsgard field development consists of three main floating production and storage units linked by 36 flexible risers. The operating conditions are characterized by high temperatures (130 °Celsius design temperature) and high pressures (up 500 bars injection pressure) combined with large gas volumes. Hence, the riser monitoring system is extremely important for a safe and reliable operation of those risers. Statoil decided in 2001 to develop a reliable Pipe Integrity Management (PIM) system with Technip-Coflexip. The PIM ystem is not intended to substitute the Operator's day to day monitoring system, which remains the responsibility of the Operator's organization. The overall objectives of the PIM system can be summarized as follow:A transfer of the relevant operational data from the Operator's database into the PIM must be done regularly to ensure continuous verification and backup of the riser data, and verification of the risers. Annual transfer is chosen for Åsgard. The frequency may be increased if required.