bluuebunny/crossref_metadata_2025 huggingface dataset:
The Ceiba Field FPSOs for phase 1 & 1A
Authors: Daviknes Morten A. , Hannisdal Nils-Erik
Published: October 2008

Bergesen dy Offshore have provided the FPSOs for both phase 1 and 1A developments of the Ceiba Field, with ABB as their process subcontractor designing, fabricating, and operating the required process facilities.

The phase 1 FPSO Sendje Berge was in operation 14 months after Triton's first oil discovery at the Ceiba Field. The upgraded (phase 1A) FPSO, the Sendje Ceiba, produced First Oil 14 months after Triton ordered the additional process modules.

This paper describes how the Bergesen generic FPSOs were modified to meet Triton's requirements for phase 1 and 1A developments, installed in field and started up, all within the ambitious schedules required by Triton.

Introduction

In October 1999 Bergesen presented the concept of a Generic FPSO to Triton Energy (TE). This coincided with Triton having issued their tender for Early Production System on the Ceiba field. The specifications and the schedule for Bergesen's first Generic FPSO were a close match to the requirements set by Triton for their EPS. In addition, the FPSO provided a very good platform for a phased development of the Ceiba field.

Moreover, the business cultures of Triton and Bergesen Offshore matched. Being part of a major shipping company, Bergesen Offshore is focused on the services to be provided, i.e. to produce oil, rather than the engineering focus often found in big offshore projects.

Generic FPSO - "The Basis"

Bergesen Offshore was founded 1999 with the objective to develop Low cost, Tanker based Floating Production Systems for use in benign areas, such as offshore West Africa.

Oil-field characteristics were gathered from oil companies with current and future activities offshore West Africa. This provided the basis for developing a Generic FPSO, which was to have process and utility systems suitable for a large variety of fields. The design should also allow for simple modifications and upgrades where this is required from operators.

In short, the FPSO should be characterised by:Designed for a wide range of fieldsLow cost to be attractive even for EPS and small fieldsFlexible design to allow for easy field specific upgradesWell suited for phased development

The two main factors that support these goals are:Tankers with ample deck spaceModularized and fit for purpose process design

Bergesen did a bid-round with several process suppliers in order to find the one that would support our objective. The selection of ABB was based on:Lean and Mean attitudeHardware-as opposed to engineering orientedFocus on delivery time.

Key factors in the design of the process are:Flexible separation design (high capacity and prepared for variety of configurations of internals.Large heat exchanger capacities.Prepared to interface various additional equipment and injection points if reservoir characteristics change.
Safety Restraint System for High-Pressure Oilfield Piping
Authors: Matzner Mark , Hayes Glenn
Published: October 2008

Conveying energized fluid through piping presents a significant hazard with the potential for explosion in the event of a component failure. A method is presented for a simple restraint system that limits the movement of piping to a contained area. Basic practical design equations and considerations useful for piping constraints are presented.

Introduction:

The safe constraint of piping used to convey highly energized fluid is essential for safety, but has proved to be a difficult task to accomplish. This has been especially true for temporary well service applications where piping must be light enough to assemble and remove quickly, and does not usually have the benefit of permanent anchors at the worksite.

Energized fluids, such as pressurized nitrogen or C02, have high explosive potential due to their stored energy. While pressurized liquids present their own kind of danger, a compressed gas has enormous potential for damage if freed rapidly. If a piping assembly fails, the initial forces released are those of the static pressure. Compounding the problem are the acceleration forces created as the stored medium continues to evacuate the piping. Both forces continue as long as any pressurized fluid remains in the system. The acceleration forces are responsible for most of the danger by causing the piping to move violently, placing personnel and equipment at risk.

Testing has shown that constraints with limited elasticity, such as wire rope, perform poorly in high pressure situations. The lack of a constraint's ability to dissipate the discharge energy is a reflection of not only its strength, but also its toughness. The solution to this problem is a flowline restraint system (FSR), developed by us, that manages to contain the damaged piping within a limited zone of danger.

The FSR system consists of members of tough synthetic loops that are strung the length of the piping and held in place by smaller loops attached at key points along the piping. This assembly is terminated at each end by anchoring to a substantial member such as the wellhead or a pumping truck for land based operations. Suitable structural tie-downs can be substituted for the truck and wellhead in offshore operations. Supplementary restraining loops are normally provided to further minimize flowline movement.

Theory and definitions:

The rapid discharge of energized fluid, such as pressurized nitrogen, will occur if a portion of the conduit piping fails. J.L. Stromberg and J.B. Surjaatmadja1 found that the forces applied to damaging the piping are proportional to the energy of the discharging fluid. They deduced that the steady state force of ejecting gas supplied by an infinite reservoir can be described by the following equation. (Mathematical equation available in full paper) The first set of terms on the right of the above equation represents the forces generated by the fluid acceleration out of the pipe. The second represents the static pressure force generated over the cross sectional area of the pipe at the exit.
Single Trip Pigging of Gas Lines during Late Field Life
Authors: Mandke J.S. , Shen Harry , Roscoe John
Published: October 2008

For flowlines used to tieback marginal fields, pigging is an essential component of the associated flow assurance solution. Single trip pigging using a single line is being pursued by the offshore industry as an economical alternative to round trip pigging using dual flowlines because of the potential savings in CAPEX and OPEX. Recently, the industry has developed subsea pig launchers which are specifically designed for deepwater and ultra-deepwater applications. However, there are significant operational challenges associated with single trip pigging that need to be resolved.

This paper draws attention to potential difficulties in the pigging of multiphase gas lines during late life field condition when the line is likely to hold a large amount of liquid. A pig travelling through such a flowline is likely to stall at the base of a deepwater riser due to the buildup of high static head of liquid column in front of it and insufficient drive energy provided by the reservoir fluid. There are some options such as using gas lift at riser base, which are available to deal with this problem. Pigging with bypass is another cost effective method to mitigate this problem. Using a hypothetical field, pigging simulation results from OLGA 2000 are presented to demonstrate how inclusion of 10 to 15% bypass in the pig benefits the pigging operation. Typical pipe cleaning pigs are limited to 3 to 5% bypass.

Another associated issue is the challenge of handling large quantities of liquid arriving rapidly on the platform topside during the pigging operation. The platform topside process train is generally not designed to handle liquid inflow at such high rates. Some potential solutions to this problem have been discussed. The optimum solution for liquid handling will have to be developed using the field specific data.

Introduction

Marginal fields in deepwater and ultra-deepwater are being developed by using tiebacks to existing nearby host platforms. Such tieback systems invariably require periodic pigging of flowlines as a part of the flow assurance solution. The traditional method of pigging deepwater flowlines has been to use two lines that connect the host platform with the subsea manifold or tree so as to provide a round trip pigging loop. In this case, the pigs are launched from the platform and received on the platform. Usually, the CAPEX for round-trip pigging systems is high. In addition, the requirement to shut-in wells, i.e. deferment of production and to buy back pig driving fluids from export lines during pigging operations could result in high OPEX. An economic alternative to round trip pigging is to use a single trip pigging system which includes a single flowline and a subsea pig launcher. Such systems utilize the production fluids to drive the pigs and there is a minimal interruption in the subsea well production. A subsea pig launcher has been successfully operated in ETAP field in the North Sea [1] since fall of 1998.
Girassol: The Biggest FPSO in the World: As Seen by Its Contractor
Authors: Loez Bernard
Published: October 2008

This paper describes the engineering, procurement, construction and installation (EPCI) issues encountered during the construction and assembly of the floating production, storage and offloading (FPSO) system chosen for the Girassol development, offshore Angola. This presentation is from the contractor's point of view and includes general remarks on the management of big projects.

Finally the paper adresses contractual aspects of the clientcontractor relationship, which have been carried out in a unique manner at Girassol.

Introduction

The Girassol project has been quite exceptional and it is true to say that it is greater than the sum of its parts. No matter how difficult the construction program was, however, the tale would seem banal if all of the details were recounted.

In order to avoid a tedious cascade of figures designed to demonstrate the merits of Mar Profundo Girassol, the Bouygues Offshore/Stolt Offshore joint venture, in their management of this complex project affair, it has been decided to provide the "inside story", presenting the major problems encountered and the way in which they were resolved.

Many of these problems are of a general, rather than a technical, nature and are common to the management of all major projects. In order to make this presentation more interesting, a number of famous authors have been quoted - entirely out of context, of course - in order to throw a humorous light on the matter.

In the beginning

The problems with the Girassol project began with the preparation of the tender at the end of 1997. Those in the industry are familiar with the haste with which TotalFinaElf E&P Angola decided to proceed with this development. The questions at that moment were: which type of contract for which scope of work and what type of facility was to be built and on what basis?

It was to be an FPSO, a floating unit for the production, storage and offloading of oil. It is best described as a hull with a vast production complex on its deck for the processing of oil, water and gas; storage of crude oil; re-injection of water and gas and export and metering of the crude oil.

Slide 1: Slide BFD3

The simplest and most striking way to define an FPSO is as a refinery on a super-tanker. This over-simplification masks the major difficulties on the project. It is a combination of an oil processing platform and a ship - two different cultures, different objectives, specifications, safety regulations, functions, methodologies, different contractors and construction sites. What brings them together is a bundle of interfaces and the absolute necessity for strict planning and coordination.

The objectives on such a project are so divergent that certain oil companies separate them at the contract stage. TotalFinaElf E&P Angola decided against this and one hopes that at the end of the day they are satisfied with this choice. If the economics of this decision are not apparent at first sight, the long term benefits are considerable.
Snorre B Hull: Design, Fabrication, Erection and Transportation.
Authors: Almeland Inge-Bertin , Pettersen Dag Juell
Published: October 2008

This paper gives a summary of the design basis and requirements of the Norwegian Field Development, Snorre B hull. It describes the fabrication of the hull at the Dragados Offshore yard in Spain, and highlights the critical and important features in the design. It describes the method used, the main elements in the hull and the shape of the final product. The paper includes a description of the fabrication sequence, load out, launching and towing to Norway. Experiences gained during fabrication will be discussed and summarised. A full description of the fabricated sections will be performed and this will be visualised with photos and drawings from the yard.

Description of the Floater

The Snorre B platform is a floating drilling and production unit (SSPV) consisting of a steel hull and deck structure. The hull consists of four "square rounded" columns supporting the deck. The columns are connected in the corners at the ring pontoon, which is rectangular in shape.

The deck structure has two main truss-lines in both the transverse and longitudinal directions. In addition to these trusses, there are also two major transverse bulkheads. Each corner of the deck consists of a "rounded square" box. There is a main deck and a cellar deck including a double bottom structure. Fig. 1 shows the floater, hull and deck.

Fig. 1. Snorre B deck and hull

Design

Most of the design work for Snorre B was initiated in 1998. Key factors accounted for in the structural design basis are:Regulatory requirementsEnvironmental CriteriaSafety ConsiderationsFunctional and Operational Requirements

Design criteria

Snorre B is designed for a 100 years storm condition for the location in the North Sea at a water depth of 350 metres. The extreme significant wave height for the area is 15.5 metres ULS, respectively 18 metres PLS. This is combined with a storm wind of 41 m/s. The design has an allowance as shown below:Margins: Mai 1999 August 2001Company: 3,000 tonnes 1,570 tonnesContractor: 1,850 tonnes 1,170 tonnesThe design life is 20 years. Factors are used for the fatigue life calculations.Outside hull below Splash zone: 2Splash zone: 3Above Splash zone: 1Inside hull: 1 and 2Deck general: 1Critical areas not possible to inspect: 10

The deck shall accommodate both drilling (RAM RIG), production equipment and aluminium living quarters.

Snorre B has 16 anchor lines which combine wire and 145 / 137 mm chain. These are connected to suction anchors.

Regulatory Requirements

Based upon experience gained from more recent platform development in the North Sea, design criteria and rules were established for the structural design.

Det Norske Veritas Rules for Mobile Offshore Units (DNV MOU) including supplementary requirements of Norwegian Petroleum Directorate / Norwegian Maritime Directorate and NORSOK, among other, were used as basis for design.
A Practical Procedure for the Evaluation of the Roll Motions of FPSO's Including the Non potential Damping
Authors: Orozco J.M. , Raposo C.V. , Malenica Š.
Published: October 2008

Nowadays, deep-waters are the new frontier of the latest huge oil discovers. The most common technology for oil exploration in deep waters is based on the FPSO concept. Therefore, a key element for a successful exploration of deepwater oil fields is the accurate prediction of the unit motions in order to minimize the stop production due to excessive motions and maximum accelerations to which the process plant equipment and supports are subjected.

The excessive motions of a FPSO can be caused not only due to rough weather but also due to mild weather at beam sea conditions. Beam sea conditions are faced by FPSOs in a spreading mooring configuration or even in single point mooring configuration but moored in regions where the swell sea is important, for instance, in Campos Basin offshore Brazil. In such cases, the accurate evaluation of roll motions is of prime importance. Moreover, in order to reach valuable results, a critical step is the proper evaluation of the different damping effects in particular viscous damping induced by the bilge keel, or those of risers.

The state of the art assumption is that the roll damping is composed of two parts: the linear one and the quadratic one. The former accounts for the potential wave radiation and partly to some frictional effects, while the latter accounts for drag forces, flow separation, and other non-linear effects. In practice, the linear part can usually be neglected and the only remaining damping is the quadratic part. These fact strengths the role played by the non-potential damping in a reliable evaluation of the roll motion amplitude.

In this paper, we will show the implementation of a practical procedure for the evaluation of the roll motions including the non-potential damping of a FPSO moored in a spreading configuration at Campos Basin and its validation through the comparison of the numerical results to the model tests.

Introduction

Compared to the other modes of motion, the evaluation of the roll motion appears to be much more complicated and the corresponding results more uncertain. The reasons for that are mainly related to the evaluation of the roll damping coefficient, which is usually dominated by the non-potential sources of damping. The usual procedure for calculation of the ship motions is the use of the so-called diffraction-radiation software based on the potential flow theory. The damping calculated by this kind of codes is linear and related to the wave making. As far as the linear theory is concerned the horizontal modes of motion (surge, sway, yaw) are usually out of resonance in the common sea conditions (periods of 5 to 25 seconds). In those cases the role of damping is not very important so that the potential flow theory evaluate correctly the (linear) amplitudes of these motions. The only modes of motion that may enter in the (linear) resonance are vertical modes (heave, pitch and roll) and for these motions the role of the damping is essential.
Laboratory Study of Used HMPE MODU Mooring Lines
Authors: Berryman C.T. , Dupin R.M. , Gerrits N.S.
Published: October 2008

Test results of residual properties of two 12-m HMPE synthetic fibre tether inserts individually used at four and eight deepwater wells respectively in up to 2,049 m water depths are presented against new tether test data and operational loading history. The paper concludes by demonstrating negligible changes in performance from new unused synthetic fibre rope and provides design engineers with new performance data.

Introduction

In May 2000 Unocal Indonesia, Transocean Sedco Forex, Marlow Ropes and DSM High Performance Fibres set an industry first by successfully utilising High Modulus Polyethylene (HMPE) synthetic fibre rope to moor a MODU (Mobile Offshore Drilling Unit) in 2,049 m. The HMPE fibre rope moorings were used at eight well locations in water depths ranging from 1,219 m to 2,049 m.

After completion of the eight-well drilling program two 12-m in-series inserts were recovered for laboratory evaluation. This aimed to assess the residual properties and remaining service life of the HMPE ropes and compare the data to new tether data and prediction tools used in the design of new mooring tethers. The evaluation included residual strength, residual tension-torque fatigue performance of the HMPE tether loaded in line with a conventional 6-strand wire, microscopic analysis, residual creep characteristics and visual inspection. Properties such as elongation, stiffness, rotation, internal condition and the residual strength of both the HMPE tether and the wire after completion of the fatigue test were evaluated.

History of Use

In the spring of 1999 Unocal Indonesia began planning an eight to ten well deepwater exploration drilling program in 1,676 m to 1,981 m water depths offshore East Kalimantan in the Makassar Strait. At that time Unocal's surface stack drilling capability from the Sedco 601 semi-submersible drilling rig was limited to water depths of about 1,524 m with a conventional wire-chain mooring system. To drill in deeper water required introducing a component that reduced the dead weight of the mooring system, yet was easily installed with local anchor handling vessels (AHVs). After evaluating several options, Unocal Indonesia contracted with Marlow Ropes and DSM High Performance Fibres for constructing ten 914-m long Superline Steelite Xtra Dyneema fibre ropes with a 3502 kN minimum spliced breaking load. The fibre ropes were used at eight well locations between November 1999 and June 2000.

Given that the moorings would be non-torque balanced, it was decided to limit the fibre rope use to an eight to ten well drilling program, or not exceeding a period of one year's use. Two 12-m long fibre rope inserts were placed into the mooring systems for testing at the end of the drilling program.

Figure 1 shows a general schematic of a mooring leg and the positions of the HMPE rope and test insert. The HMPE ropes were inserted between the rig's 6-strand wire and a pre-installed (pre-laid) wire-chain mooring system consisting of 6-strand steel wire rope and chain.
Redefining the Static Gel Strength Requirements for Cements Employed in SWF Mitigation
Authors: Mueller Dan T.
Published: October 2008

The decay of hydrostatic pressure due to gel strength development of a static cement results in a pressure underbalanced condition, which can initiate shallow water flow. By determining the static gel strength history verses time relationship of a cement slurry and calculating the annular pressure loss as a function of that static gel strength, the point in time when the pore pressure of the shallow water flow interval exceeds the annular hydrostatic pressure of the gelled cement and sea water can be predicted.

Introduction

Shallow water flow (SWF) is the most feared of the geohazards associated with deepwater drilling. Normally encountered in the upper 2,500 ft of a deepwater well, SWF occurs when over-pressured, low-shear strength sands are drilled while the wellbore is in an underbalanced state. SWF is a slurry of water and sand, which if sufficiently pressured, flows up the wellbore to the sea floor. Once initiated, SWF's are capable of impacting well construction in any number of ways including:The deposition of large amounts of sediment around the wellhead to a point at which re-entering the wellbore becomes problematic;The abrasive force of the SWF eroding the sediment at the formation-cement sheath interface to produce a flow conduit back to the mudline, even at considerable depths below mudline;The SWF removing a sufficient volume of formation to produce a near-wellbore subsidence which can shear the casing;The SWF producing an annular washout which induces buckling of the casing due to lack of lateral support.

The tophole section of a deepwater well may contain several individual sand bodies each with its own flow potential. Above the individual sand body is usually a low-permeability, clay-rich section. The clay interval serves as an impermeable boundary, which prohibits the pressure within the sand body from equilibrating with its surroundings. A typical SWF sand is 10 to 50 ft in thickness, has a permeability in the range of 1 ? 10 Darcies and a porosity in excess of 40%. Shallow water flow has been experienced in the North Sea, Trinidad, Norwegian Sea, Caspian Sea, the Gulf of Mexico1 and West Africa.

It is important to note that SWF sands differ markedly in physical properties from the more familiar reservoir rocks. The sands are considered to be in transition between unconsolidated sediment and rock.2 The semi-solid nature of the sediments encountered in the tophole section is demonstrated during the drilling process: a rate of penetration (ROP) of 150 to 300 ft/hr is common. In fact, the biggest drilling challenge in the tophole section is not ROP, but solids/gumbo removal.

Flow Mechanism

The metastable nature of the sands found in the tophole section is the key to understanding why the sands flow. Huffman and Castagna propose two possible mechanisms:3 First, is that the sands are already in an initial stage of failure, and the dynamic load imparted by drilling is sufficient to initiate flow.
Bonga: Oil Off-loading System using Flexible Pipe
Authors: Lebon L. , Remery J.
Published: October 2008

A number of large deep water oil fields offshore West Africa are developed on the basis of a large spread moored FPSO with a CALM buoy located at a safe distance to allow tankers to moor alongside for oil off-loading operations. For the transport of the stabilized oil from the FPSO to the CALM buoy, the proposed base case for a number of fields has been to use large diameter steel pipe hung between the two floaters. Design experience has however shown that the fatigue life of such an off-loading line is extremely critical and as such negatively influences the reliability of the system.

By adapting the configuration and/or using flexible pipe instead of rigid steel pipe, the fatigue life can be significantly increased. A different configuration can reduce the loads in the pipe and a flexible pipe, by its inherent compliance, is significantly less sensitive to curvature variations and will thus have a longer fatigue life than a rigid steel pipe.

After a general overview of the impact of different design choices on the total solution and the feasibility of flexible pipe oil off-loading systems, this paper presents in details the flexible pipe system that has been chosen for Shell's Bonga field offshore Nigeria. It addresses the main phases of design: namely, the flow aspects that dictate the number of lines and the operating pressures, the mechanical and hydrodynamic aspects that determine the structural integrity and the fatigue life and also the installation operations.

1 INTRODUCTION

For a number of Ultra Deep Water fields West of Africa the export of oil is performed by tanker. However as the FPSO is spread moored it is not practical for the tanker to unload directly from the FPSO barge. Therefore a separate offloading buoy situated approximately 1 nautical mile from the FPSO is used for this purpose. The export of the stabilised oil is typically achieved through a subsurface partially buoyant line. The line is given buoyancy in it's middle section to obtain a wave shape and as such provide a certain amount of flexibility to accommodate relative motions of the off-loading buoy and the FPSO.

Design experience in the industry has shown that fatigue is a real problem for rigid steel pipe oil off-loading systems and that to achieve the specified fatigue life special mitigating measures are often required (double flex-joints, thick steel forgings for offshore welds and VIV suppression strakes) (ref. 1 and 3). These specific items are not required when flexible pipe is used, which is therefore considered a good alternative as is illustrated in this paper.

2 INFLUENCE OF THE MAIN DESIGN PHASES OF AN OIL OFF-LOADING SYSTEM

2.1 Flow Aspects.

To optimise the design of an oil offloading system, thus to maximise the flowrate, the following parameters need to be considered :Pressure drop allowable along the lines (inlet pressure and requested outlet pressure)Diameter and type of line (internal roughness) of the linesNumber of lines

This section describes how these parameters influence the design and show how optimisation is possible.
Reelability of Steel Bulkheads for Pipe-in-Pipe
Authors: Giacomelli Yvan , Bell Mike
Published: October 2008

Technip-Coflexip has recently developed a technical solution to allow the reeling of a pipe-in-pipe bulkhead. The reeling of bulkheads compared to welding bulkheads into the pipe-inpipe offshore will save a significant amount of offshore time. The design is presented, fabrication procedures are discussed and the results of optimization work by Finite Element analysis utilizing ABAQUS£ are included. Results from fullscale reeling trials of bulkheads on the CSO Apache reelship are also presented, proving the feasibility of this design reelable steel bulkhead design.

Introduction

Steel bulkheads can be included within pipe-in-pipe systems primarily to allow load transfers between the outer and inner pipes during installation and in-service. In addition, the use of pipe-in-pipe in deepwater necessitates an effective repair strategy in the event of a wet or propagating buckle. As bulkheads combine the functions of a buckle arrestor and a waterstop, their installation at regular intervals along the pipeline would allow the replacement of any defective section between bulkheads (Reference 1).

Reel-lay provides clients with a cost effective installation method and high quality installed pipeline. The inclusion of bulkheads during the onshore fabrication procedure of a pipein-pipe system requires a conventional bulkhead design to be further developed in order to achieve a fast assembly and remove the need for half shells. The design, construction and testing of a pipe-in-pipe including an innovative modular bulkhead based on a combination of threaded parts is therefore described. The assessment of the bulkhead behavior during the reeling process and under various loading conditions was carried out by Finite Element Analysis. This theoretical work was validated by a full-scale prototype test performed on the CSO Apache reel-lay vessel and the results are presented hereinafter.

Innovative Design

For the reel lay method individual stalks of pipe-in-pipe up to approximately 5000ft in length are prefabricated on the designated spoolbase prior to vessel arrival. The flowline and carrier pipes are fabricated separately before the flowline systematically inserted into the carrier while spacers and insulation are applied (Reference 2). On arrival of the pipelay vessel the first stalk is spooled onto the reel preceded by a lead string. Each subsequent stalk is connected to the previous by two tie-in welds. First the flowline ends are brought together and welded. Then the carrier pipe of the trailing stalk is slid over the flowline to close the gap for the second weld.

Bulkhead spacing will be dependent on the project requirements. Stalk lengths can be modified to allow the insertion of bulkheads in the pipe-in-pipe assembly during tie in operations. The inclusion of a classical one piece forged mid-line bulkhead in such a fabrication procedure will require the use of half shells. Figure 3 describes a step-by-step assembly of a forged bulkhead at the tie-in station.
Performance Comparisons Of Scuba Divers Vs Submersible Manipulator Controllers In Undersea Work
Authors: Pesch Alan J. , Hill Robert G. , Klepser William F.
Published: October 2008

The basic problem to which this research program is devoted is the current inability of ocean engineering personnel to design undersea hardware systems which complement the capabilities of the human operator. This problem Stems largely from a lack of quantitative research data on the relative shortcomings and strong points of divers and a similar lack of data describing the capabilities of various underseamanipulator work systems. The research has been oriented toward quantitative data collection which describes how rapidly, how proficiently, and under what circumstances an operator can or cannot perform tasks of what difficulty, both as a diver and as a manipulator operator aboard a submersible. The results are presented in the form of a ratio of performance time for the diver versus a manipulator. The conclusions of this research are based on data collected in a wet simulation facility. The tasks range from simple tasks such as sample gathering, valve turning and hooking to tasks of increasing difficulty such as cable rigging, unbolting, Hansen connect/disconnect functions, hole drilling, hole tapping, and pipe threading. The overall ratio for all tasks studied was 1/4; e.g., a diver was four times faster than a rate-controlled manipulator. More importantly, depending on the task, this ratio changed drastically. For example, the tapping of holes in 1/2inch aluminum plate was performed equally fast by the diver and the manipulator (1/1); however, the diver frequently broke taps. Another task required the connecting and disconnecting of a 1/2-inch Hansen quick-disconnect fitting which the diver performed 31 times faster than the manipulator.

The diver also-always ensured that the connection was securely made. Conclusions are presented in this article in terms of which tasks and task aspects contributed most to the observed positive or negative performance of divers and manipulator operators.(This work was sponsored by the Office of Naval Research under Contract NOOO14-69-C-0 I 68, NR196090/11-27-68 (455).)

INTRODUCTION

A major consideration in the development, operation, and maintenance of subsurface installations is the type of implementation methodology selected to perform the work. Examples include surface-controlled rigging, a direct diver deployed in any of serveral configurations, and submersibles equipped with manipulators.

Experience with the performance capacities of these methodologies varies from a great deal of experience in surface-controlled rigging to somewhat less experience in the diver area, to marginal experience with submersible manipulator systems. A selection from among these approaches would consider many variables, including depth, environment, cost, and personnel. The objective of our research is to improve the level of experience and, therefore, to increase the information available for decision making on one of these variables - performance ability of the operator.
An Analytical and Experimental Study of the Box-Type Joint for the Offshore Structure
Authors: Arita Yuko , Yamashita Masahiro
Published: October 2008

This paper describes an experimental and analytical study on the states of stresses of a box-type joint and a further application of this type to a column stabilized drilling unit.

The box-type joint has been developed in lieu of the conventional tubular joint. The tubular members can be connected compactly by having them reshaped and formed into the box type section at the area close to the joint.. Regarding the transfer of load and the distribution of stress at joint, we have carried out the structural experiments using the three different types of models and analysis by the finite element method.

The result of the above shows that the distribution of stress at this joint is not so complicated as that at the tubular joint and that the coefficient of stress concentration in the former is less than that in the latter. The configuration of the box-type joint being comparatively simple, the analysis can be easily and accurately made and the flow of stresses can be clearly understood.

We have found that the local bending stress occurring around the area forming the box-type section from that of tubular shape was decreased by adding a suitable ring stiffener to this area and that the buckling strength in this area was sufficient.

It is expected that this type of joint having been already applied to the column stabilized drilling unit under construction at our Hiroshima Shipyard will prove to be perfectly effective and satisfactory.

INTRODUCTION

With the recent ocean development towards deeper and rougher areas of the sea, the column stabilized drilling unit and the drilling platform have come to be required to be larger in size and more reliable than ever before. To these offshore structures are usually applied tubular members to minimize the effects of waves, wind and tidal currents.

As is known, the thin cylindrical shell has such desirable characteristics, from the view point of structural strength, that it has superior properties in elasticity to the other ones. In order to make the best use of these characteristics, strength of the connecting joint between members has to be 'equal to or greater than of the members to be connected. This may well explain that the majority Taking into consideration the course of development of the joints in the offshore structures built for the past ten years, concerning the fixed type of the offshore structure, the gusset system was adopted, as a typical pipe structure for the tanker berth dolphin of the Cook Inlet; the flare joint system was also adopted for the, drilling platform operating in the same place.
Fatigue Tests On Anchor Chain-Cable
Authors: de Laval Gilbert
Published: October 2008

Fatigue tests have been carried out on anchor chain-cable. Fatigue tests on steel normally are performed on specially machined specimens. Such a specimen is given an exceptionally smooth surface in order to eliminate as much as possible the probable influence of surface defects on the fatigue strength of the steel.

In order to obtain, in this case, a more realistic picture of the fatigue strength of anchor chain-cable than is possible with the ordinary fatigue test, these tests have been carried out on the chain links proper.

Three-link samples of 2-in. oilrig chain (Fig. 1) were tested at six different maximum loads. Chemical composition:C = 0.27 percentSi = 0.27 percentMn = 1.60 percentP = 0.024 percentS = 0.012 percentN = 0.008 percentMechanical properties:yield strength 47 kp/sq mm 67,000 psitensile strength 70 kp/sq mm 100,000 psielongation = 24 percentimpact resistance = 11 kpm at O°C, Charpy V-notchTesting requirements:proof load = 147 mp 322,000 lbbreaking load = 222 mp '" 488,000 lb

Before fatigue tests all samples were subject to proof load.

At each maximum load five samples were tested. The tests were made in an AMSLER 100 mp tensile testing machine with pulsator at the Government Testing Institute, Stockholm, Sweden The frequency used was 285 load changes/min and the amplitude varied between the maximum load and a minimum load of 5 mp.

The tests were carried out at room temperature in dry conditions. Records of test results can be studied in the table (Fig. 2) and diagram (Fig. 3) which show the number of load changes at rupture (small circles) at different loads. Mean values are indicated by big circles.

The samples were pulled to destruction or at least 2 million times.

Discussion Of Results

The ruptures occurred in the same place in the bent part of the link with location according to Fig. 4.

In Fig. 5, the mean values of Fig. 3 have been transformed to stress at maximum load. This stress value is simply the mean stress on the chain section obtained by dividing themaximum with the cross-section of the link [2 (?D2)/4] It is !mown that stresses in some parts of the link under load are considerably higher than this mean value.

It is perhaps allowable to define a fatigue limit for chain-cable. This limit could be defined as the maximum load at which the chain sample withstands at least 2 million load reversals without rupture.
Control Simulation Study of a Dynamically Positioned Pipelay Barge System for Deepwater Operation
Authors: Harris Bill J. , Morgan William A. , Stuart Francis X.
Published: October 2008

Extension of offshore pipe laying capabilities to water depths of 1500 feet or more is dependent upon the development of methods of controlling the pipelay barge at these depths.

Dynamic positioning through regulation of propulsion units is one method of control currently being considered. A simulation study was performed on a hybrid computer to investigate this technique, using direct digital control of the variables (pipe tension, pipe lateral load and barge position). In the study it was possible not only to evaluate the behavior of the system but ultimately to develop a successful scheme for controlling it.

Introduction

Recent years have seen offshore wells and pipelines extend into water depths over 300 feet. Now, with the latest techniques in drilling, platform construction, underwater completion and diving, technology exists that permits production in much deeper water. Accordingly, Brown &Root commenced an investigation of the means to extend their pipe laying capabilities up to 1500 feet or more in depth.

One of the major obstacles to pipelay barge operation in water depths much beyond the capability of present pipelay barges is the difficulty in maintaining barge position and progressing along the desired course using anchoring techniques. Anchor lines, even now, are up to 5000 feet long and they become longer for deeper water. In addition to the handling problems for these long wires, their permits excursions in position which might damage the pipe line. Both of these problems become progressively worse as water depth increases. For these reasons, the study of the deep water problem has centered around the dynamic positioning concept for control of the barge.

Dynamic positioning is not a new development It has been used on drilling vessels for a number of years. However, the pipelay barge application requires several unique features.

First, the lay barge does not have the capability of orienting itself to minimize environmental conditions, but must maintain heading in consideration of the direction of the intended pipeline. Thus power requirements and the forces tending to move the barge off station are both greater.

Second, the barge does not maintain a specific location, but must move either -continuously or in increments equal to each new joint of pipe as it is assembled. into the line on deck. Thus, permanently fixed sonar units or other such permanent facilities for maintaining a single location are unusable.

Third, some predetermined axial force in the pipe must be maintained in order to suspend the pipe from the curved stinger without overstressing. At the same time, the lateral load of the stinger on the pipe must be minimized to prevent lateral buckling.
Geotechnical Design of the Barracuda and Caratinga Suction Anchors
Authors: Hesar M.
Published: October 2008

The Paper presents the methodologies adopted for the design of mooring and riser anchors of the P43 and P48 FPSOs due to be installed in 2003 in deep water Campos Basin, offshore Brazil. It is shown how an efficient semi-analytical 3D finite element model can be used as a routine design tool for calculating the pull-out capacity of cylindrical suction anchors under combined horizontal and vertical loading. The speed of the FE model has allowed pull-out capacity contours to be developed which help in the selection of limiting installation tolerances. Fully coupled axisymmetric finite element consolidation analyses of the set-up phenomenon have been described in which the initial excess pore pressure field is established by simulating the final penetration stages of the skirts.

Introduction

The Barracuda and Caratinga fields are located in deepwater Campos Basin, some 150 km offshore Brazil. The average water depth is 825m at Barracuda and 1030m at Caratinga. A taut-leg spread mooring system has been adopted for both the Barracuda (P43) and Caratinga (P48) FPSOs. Each FPSO is moored by 18 lines, ten at the stern and eight at the bow. The mooring lines are made of polyester rope, combined with lengths of chain at the fairlead and seabed ends, Wibner1.

Various types of anchor were considered in the initial phases of the project. Suction anchors were selected as the preferred option for the following reasons, Sparrevik2:Relatively accurate positioning on the seabed, which isimportant in fields congested with flow lines and subsea facilities,Economical and simple installation method, avoiding the need for pile driving in deepwater or dragging and proof loading.Reasonably well-established design methods compared to other types of anchor, even though no Standard Code of Practice is yet available.

In addition to the 36 mooring suction anchors, 52 suction anchors in four different sizes were designed for restraint of the risers. The subject of this paper is the geotechnical in-place capacity of mooring anchors only and excludes installation aspects. The suction anchors were designed to comply with ABS Rules3 and current industry practice for 20 years service life.

Site Investigation

An integrated approach to SI was taken4,5. A comprehensive geophysical and geotechnical site investigation was performed in spring 2001 from the vessel Rockwater-1. Subsea7 (formerly Halliburton Subsea), performed the geophysical surveys consisting of swathe bathymetry, ROV high resolution sub-bottom profiling and side scan sonar imaging, while Fugro BV performed the following geotechnical SI from the same vessel:66 WHEELDRIVE Piezo-cone penetration testing (CPTU) to 30m penetration,12 WHEELDRIVE insitu vane tests up to 20m. One test every 0.4m and remoulded shear strength determination every second test,39 Push-in Piston cores up to 20m. The SI was followed by a programme of monotonic and cyclic laboratory testing both in Holland and the UK.
The First Year's Achievements of the Intelligent Well Reliability Group
Authors: Hother John
Published: October 2008

The Intelligent Well Reliability Group was formed as a spinout from the SPE's Smart Wells Forum in Europe in September 2001, and the contracts were signed in February 2003. The Group's objective is to increase the uptake of smart wells by promoting better understanding, and appropriate use of reliability methods and analysis. The 12 participants are a mix of operators and vendors, with an independent coordinator acting as 'honest broker'.

This paper reports on the work of the first 'year' of the Group, covering-A compendium of the parameters and metrics of reliability to establish a common language across the industry (completed);Guidelines on how best to address reliability in requirement specifications (review draft);Survey of system reliability analysis and prediction techniques (in progress);Survey of reliability testing and evaluation methods (in progress);Guidelines on the exchange of confidential information between the supplier and operator (in progress);Inventory of good operational practices and procedures for improving reliability (in progress). There will, no doubt, be significantly more completed work to report in the presentation at the OTC in May 2003.

The results can be applied by both operators and vendors, in the process of design, tendering, installation and operation of Intelligent Wells. Using the results will help to ensure that -the requirements are properly specified;the design meets the requirements;the design has been properly analysed and tested;the installation is properly controlled;the operational procedures extract the best performance. Oil operators have declared that improving reliability is at the top of their agenda - in international conferences and in direct dialogue with the rest of the industry. They have published performance reviews and set challenging objectives for reliability in service. Operators and service companies realise that they need to work together to achieve these goals. The results of this Joint Industry Project are expected to contribute significantly to the ability of the industry to meet the operators' objectives.

1. Overview of the Project

The Intelligent Well Reliability Group was formed as a spinout from the SPE's Smart Wells Forum in Europe. In the forum sessions, reliability and its perception had been identified as key issues. However, each SPE Forum is a oneoff event, and some of the key players wanted a new way of addressing these issues with continuity. At a break-out meeting of the key players, Proneta was tasked with formulating a draft Charter and organizing an inaugural meeting to turn that into an agreed Charter. That first meeting of the Group was in May 2002 in Galveston, Texas, the Charter was revised and agreed, and the contractual basis for the Group project was established. These are all described below, along with the results of the work to date (January 2003). It is expected that there will be further results to be reported by the time of the presentation of this paper at the SPE OTC in May 2003 in Houston, Texas.