bluuebunny/crossref_metadata_2025 huggingface dataset:
Design Aspects of Platform for a Floating Nuclear Plant
Authors: Dotson C. , Anderson R.S.
Published: October 2008

Tenneco and Westinghouse Corporations formed a joint venture in May, 1972, designated Offshore Power Systems, to market, design and manufacture standard nuclear power plants for offshore installation. The plant design is a totally integrated nuclear generating station, mounted on a floating platform and moored within a protective breakwater. The plant is standardized such that it can be sited along the East and Gulf Coasts of the United States. This paper discusses the design of the platform which serves as the foundation for the Floating Nuclear Plant.

INTRODUCTION

The concept of offshore siting of nuclear power plants is not new; studies and investigations in this area date back to at least the mid-sixties. Although studies concluded that the concept offered some advantages, in depth studies were not conducted to fully determine that the concept was both technically and economically feasible.

The worsening trends in finding suitable land sites along the coast, power plant cost escalation and schedule delays, the growing concern of environmental impact, and a desire for standardization to facilitate the licensing process have all lent impetus to a serious look at offshore siting.

The Special Project Division of Westinghouse was created in April, 1971, to devote fu11time effort to a technical and economic study of the power plant and a manufacturing facility. They were joined by approximately forty five employees from Newport News Shipbuilding, a Tenneco subsidiary, in the summer of 1971. The results of the study led to the formation of a joint venture designated Offshore Power Systems located in Jacksonville, Florida, and the signing of a contract for two units with Public Service Electric and Gas Company of New Jersey.

Both the nuclear power plant and its supporting platform utilize existing and proven technology. Plant components and systems are nearly identical with those of comparable licensed land plants. The nuclear steam supply system is a typical Westinghouse four-loop 3425-MWt pressurized water reactor with ice condenser containment. Figure 1 is a sectional view of the plant through the containment. The power generation plant contains a standard Westinghouse turbine generator unit with a net output of 1150 MWe. Thus, the only real innovation in power plant design is the platform which will be moored in a protective basin.

PLATFORM STRUCTURE

The platform is approximately 400 feet long, 378 feet wide and 40 feet deep with a plant displacement of about 150,000 short tons. Full depth bulkheads run in both the longitudinal and transverse directions extending the length and width of the platform to form a grid. Along the 378 foot width bulkheads are located at regular intervals of 37 feet; 9 inches. Along the 400 foot length bulkhead spacing varies from approximately 47 feet to 82 feet.
Wrong Paradigms in the Actual Well Testing Analysis - Oil Reservoir Case
Authors: Medina R. A.
Published: October 2008

At first, four misconceptions found in the current state-of-art of the oil well testing are revised in detail in this paper. A mathematical demonstration, a historical review and a field example are presented to support these four technical observations: (1) The wrong use of the volumetric factor B in the actual pseudosteady-state flow equations. (2) The use of semi-empirical correlations, like those of Vogel, Fetkovich or Wiggins, to analyze IPR curves. (3) The calculation of the maximum oil flow rate potential of a well at a wellbore pressure of zero. (4) The historically rooted paradigm of underestimating the Deliverability Tests capacity to determine reservoir properties.

Then, the revision of these four wrong paradigms conveys to the introduction of a new approach for obtaining reservoir information: the “Productivity State Analysis”. The most promissory feature of this new Well Testing approach is the opportunity that it opens to obtain the information through tubinghead pressures measurements.

Finally, two ambitious applications of these surface tests for the industry are proposed: (a) the pre- and post- evaluation of every workover/stimulation job, and (b) the periodic Productivity-State-Analysis of reservoirs. This last kind of reservoir evaluation could both improve dramatically our actual understanding of their complex dynamic reality and give us an index value for our efficiency in producing from them.

Introduction

To improve the efficiency in both the production of the wells and the exploitation of the reservoirs, it is indispensable to obtain opportune key-information about them. In this paper, after the discussion of four technical observations to the current Well Testing state-of-art, a new Well Testing approach is presented to determine key well-reservoir information from tubinghead measurements, which means low-cost tests and the opportunity to evaluate greater amounts of wells.
Seafloor Scour Protection for a Semi-Submersible Drilling Rig on the Nova Scotian Shelf
Authors: Wilson N.D. , Abel W.D.
Published: October 2008

Protection against scour became a prime consideration when it was proposed to set the Sedco H semi-submersible drilling rig on the seafloor in 90 feet of water to drill an exploratory well on the Nova Scotian Shelf. It was expected that ocean current velocities adjacent to the 80-foot diameter pontoons of the Sedco H would be accelerated significantly to cause scour of the sandy bottom around the pontoons and endanger the stability of the rig.

Laboratory model experiments were conducted and the results confirmed that scour would occur if no protection were used. Further experiments were then conducted to determine the rate of scour and the amount of protection that would be required to prevent scour. After several model test runs, it was determined that scour protection extending 50 feet from the edge of each pontoon would be required. An inexpensive nylon mesh material was chosen as the protection material to be laid as a.mat on the ocean floor.

On-site experiments prior to the arrival of the rig were performed to develop working techniques and methods of placing the 7500 square of material required for the installation. Sample strips of the nylon mesh were installed by divers to evaluate its sand retention ability and handling characteristics at the varying current velocities. Based on the results of the on-site work, the nylon material was prepared for efficient underwater handling and a program was developed for fastening it to the ocean floor using steel pins and sandbags.

During drilling of the well, regular inspections were conducted to monitor the mat installation. Further verification of the laboratory prediction of the scour was made by removing small strips of the mat at one of the pontoons and monitoring the rate and amount of scour. It was found that oscillating currents induced by waves had a larger influence in causing scour than did tidal currents.

INTRODUCTION

Scour protection is often required to prevent scour from occurring around marine structures. This was the case when it was proposed to set the semi-submersible drilling rig Sedco H on the seafloor to drill the Mobi1-Tetco Thebaud P-84 well in 90 feet of water six miles southwest of Sable Island during the summer of 1972. Figure 1 shows the location of the well.

Normal tidal currents in the area reach a maximum of about 1.5 knots (0.77 metres/sec.). Scour was expected since it was known that the seafloor was fine sand and that the 80-foot diameter Sedco H.pontoons would cause the current velocities around the pontoons to be accelerated considerably. However, it was impossible to predict theoretically the amount of scour or the amount of scour protection that would be required mainly because the relationship between current velocity, rate of scour, scour depth, and grain size distribution is not yet well defined.
Underreamed Footings Support Offshore Platforms In The North Sea
Authors: Ehlers Clarence J. , Bowles William R.
Published: October 2008

In selecting a foundation element for support of template-type structures in the Ekofisk Field in the North Sea, it was concluded that dense sands and hard clays would limit installation of pipe piles by driving alone to a penetration much less than the required penetration, and that installation problems and design uncertainties made a grouted insert pipe pile marginally desirable. Phillips Petroleum Company originated the idea of using an underreamed footing excavated beneath a driven pipe pile in a stratum of hard clay at about 100-ft penetration below the seafloor. Analysis of the underreamed footing from both technical and construction standpoints indicates that the use of this type of foundation element is feasible.

Two platforms are now supported in 230 ft of water on a total of 36 underreamed footings with base diameters ranging from 9 to 14 ft. The underreamed footings were installed using rotary drilling equipment supported on a temporary working deck placed on the substructure or jacket. No major problems were-encountered during construction.

INTRODUCTION

A giant oil and gas strike, designated as the Ekofisk Field, was made in the North Sea in 1969 by Phillips Petroleum Company. The Ekofisk Field is located in the Norwegian Sector of the North Sea in Block 2/4 as shown on Fig. 1 and is approximately 190 miles south-southeast of Stavanger, Norway. In the second phase of development of the Ekofisk Field, 11 offshore structures are being installed consisting of two isolated drilling platforms and nine interconnected structures, designated Complex "C". The structures of Complex "C" are connected by a bridge system and are aligned so that the total length of the complex is in excess of one-half mile. From north to south, the structures in Complex "C" consist of a one-million barrel storage tank, a pipeline pump station platform, a bridge support structure, reinjection drilling platform, personnel quarters platform, field terminal-production platform, two bridge support structures and a flare support structure. With exception of the storage tank, all structures in the Ekofisk complex are conventional template-type structures. The one-million barrel storage tank is a unique offshore storage structure that is constructed from reinforced concrete and supported on a mat foundation bearing on the seafloor.

Foundation borings drilled at Ekofisk disclosed the presence of strong foundation soils consisting of dense sands and hard clays. The foundation element given first consideration for support of the template-type structures at Ekofisk was a driven 42-in.-OD open-end pipe pile, which is the conventional foundation element for offshore structures. Static pile capacity computations indicated that 42-in.-OD pipe piles would have to be driven to penetrations in the order of 350 ft below the seafloor to support the maximum design compressive loads of 4500 kips.
The Fai lure of the South Pass 70 "B" Platform Hurricane Camille
Authors: Sterling G.H. , Strohbeck E.E.
Published: October 2008

In August of 1969, Hurricane Camille swept across the central Gulf of Mexico making landfall on the Mississippi Coast. This major storm caused the loss of many lives and considerable property damage was inflicted on the Gulf Coast from New Orleans to Biloxi. Shell Oil Company lost its South Pass 70 "B" Platform and Gulf Oil Company lost a similar platform in ft neighboring block.

This paper discusses the evidence gathered in an intensive after-the-fact study conducted to ascertain the cause of failure of Shell's platform. The data include: post-Camille survey of above-water damage at other platforms in the area, topographical surveys, side-scan sonar runs, soil borings, and detailed diving and underwater television surveys of the fallen structure.

The data conclusively show that the South Pass 70 "B" structure failed primarily because of sea floor soil movements.

INTRODUCTION

In June 1967, several Outer Continental Shelf (OCS) lease blocks in the Gulf of Mexico were offered for competitive lease bidding by the United States Geological Survey, an agency of the Federal Government. Shell Oil Company acquired the lease rights to South Pass Block 70 in that sale1 The block is located about 15 miles southeast of the Main Pass of the Mississippi River. Its location is shown in Figure 1.

Initial design studies for a bottom supported drilling and production platform for this area had been under way prior to the lease sale. Soon after confirmation of bid acceptance, soil borings were taken using the well-known wire1ine technique.2 While Shell's experience in the Delta region had led us to expect weak clay soils, the extent and depth of the very weak clays which were found in the boring program were unexpected. An immediate concern revolved around appropriate design approaches to withstand lateral and axial pile loadings. A second, and ultimately much more serious problem, was soon hypothesized; i.e., the soils were so weak that soil movements caused by slumping or sliding actions might take place. Thus, while the design proceeded, an extensive program of research and field work to evaluate the probability of sea floor movements was undertaken.

Because of the very weak near surface soils, the bottom of the structure was extended into the soil (see Figure 2). Although this extension provided for increased stability during installation and reduced lateral deflections under routine wave loading, the structure was not designed to resist a massive soil movement of the type which occurred.

In late 1968 and early 1969, three platforms were installed in the general area one in South Pass 61 by Gulf Oil Company and two in South Pass 70 by Shell Oil. The resulting oil field became officially known as the South Pass 61 Field. The two Shell structures were named South Pass 70 "A" and 70 "B" Platforms.
Finite Element Analysis A Basis for Sea-Floor Soil Movement Design Criteria
Authors: Arnold Peter
Published: October 2008

The application of a recently proposed finite element analysis is presented as a basis for the development of wave induced sea-floor soil movement design criteria. Experience gained in the application of this analysis leads to the following conclusion: Failure to recognize the effects of pressure and cyclic loading on soil strength properties, and the influence of strength profile shape and gravity stresses can lead to unrealistic design criteria. However, used prudently as a basis for soil movement and foundation design criteria, the finite element analysis represents a significant improvement over slope stability analyses which are currently in use.

INTRODUCTION

Recent experience1,2 in the Mississippi Delta area of the Gulf of Mexico indicates that bottom pressures generated by storm waves can trigger large scale sea-floor soil movements. These movements can produce lateral forces on an offshore platform that exceed the magnitude of design level wind, wave, and current forces combined. The technology required to develop soil force and foundation design criteria can be divided into three elements:Limiting Equilibrium - What conditions are required to be present in order for soil movement to occur?Soil Response - What are the pattern and magnitudes of displacements and the state of stress in the soil during movement?Soil-Structure Interaction - How does the soil movement affect the platform?

This paper will concentrate on the conditions of limiting equilibrium and soil response, which are related to soil movements generated locally by wave bottom pressures. The soil-structure interaction problem is treated elsewhere3 The question of probability of occurrence, which includes an evaluation of wave occurrence and the relationships between wave kinematics and bottom pressures, is also of prime importance in the development of design criteria but is beyond the s cope of this paper.

A lower bound solution, employing a simplified finite element model, has recently been proposed4 to study the waveinduced soil movement problem. This static two-dimensional model includes the effects of large vertical deformations of the seafloor boundary and the nonlinear stress strain characteristics of the soil. This finite element analysis has the capability of resolving the questions of limiting equilibrium, pattern and magnitude of displacements, and state of stress, which are required in the development of design criteria. The validity of design criteria, which are developed using the results of any analytical model, will depend on at least three factors which are beyond the validity of the analytical model itself:Selection of input data, especially soil properties, which are representative of field conditions.Complete interpretation of the analytical results and their relationship to field response.Incorporation of field parameters, especially gravity forces due to bottom slope, which are not included in the analytical model.
State of the Art in Float-Overs
Authors: Seij Michel , de Groot Henk
Published: October 2008

The float-over deck installation is in use as an effective installation method since the eighties. The method has developed and the applicability has widened to heavier integrated decks and harsher environments such as West- Africa and West-Australia.

The paper describes the state of the art in float-over deck installations by an overview of a number of typical float-over operations. Each of these float-overs has a typicality related to:Integrated deck weight;Environment;Installation concept. The present state of the art has been reviewed in a SWOT analysis from a contractor's and operator's perspective. Strength, weaknesses, oppurtunities and threats have been summarized to identify a way forward for future developments.

Possibilities for the way forward to achieve the following objectives have been outlined in the paper:Improved workability;Reduced jacket slot requirements;Standardization to reduce early commitment requirements.

Introduction

Installing an integrated deck onto a jacket structure is an operation that has been executed by using semi submersible crane vessels and derrick barges already for many years. Offshore integration costs can be reduced since the integrated deck weight can be over above the capacity of (locally) available crane capacity.

The float-over deck installation is proving to be a competitive alternative for such an offshore installation operation. In recent years the concept of float-over deck installation has matured. With the help of a lengthening track record and benefits over lift operations, the float-over deck installation is taken into account as a reliable means of installing the assets. Since the float-over deck installation has been used only for a limited number of projects compared to the lifting operations performed by semi submersible crane vessel, improvements to the concept are still to be expected.

Float-over Deck Installation: Sequence

For better understanding of the advantages and dis-advantages of the float-over deck installation over semi submersible crane vessels, a brief introduction to the float-over concept is presented.

Load-Out

The load-out is the starting point of a float-over deck installation. The integrated deck will be build on-shore and needs to be loaded out onto the installation vessel. Load-outs can be performed either by self propelled modular trailers or by the use of skid tracks.

Figure 1 presents a skidded load-out of a 15.000 tons module onto self propelled installation vessel Blue Marlin. Figure 1: Skidded load-out of 15.000 tons module (available in full paper) Requirements for the load-out stage are governed by the following parameters:Integrated deck weight;Tidal range;Quayside dimensions.

Sea Transportation

After completion of the load-out, the integrated deck has to be seafastened on board the installation vessel prior to commencing sea transportation. One aspect of the transport that's always critical for a float-over transport is stability of the vessel.
Espirito Santo: The New Deepwater Frontier in Brazil
Authors: Bezerra Márcio Félix Carvalho , De Rossi Nery Vicente Milani
Published: October 2008

Petrobras has extensively acted in five simultaneous Exploration and Production frontiers in the Espirito Santo Basin, namely: gas in shallow water, light and heavy oil in deepwater, light oil in ultra deepwater and onshore. The oil and natural gas production has increased very fast over the last years; thus, contributing to the sustainability of the Brazilian scenario.

The new projects planned will require solid investments from Petrobras, in the order of US$ 9 billion up to 2011, applied mainly in the exploration and production areas. The turning point in the oil production is starting with the new deepwater production systems in the following fields:?Golfinho: (module 1 - FPSO Capixaba - 2006) and (module 2- FPSO Cidade de Vitoria -2007).?Jubarte: phase 1 (FPSO P-34 - 2006) and phase 2 (FPSO P-57 - 2010).

In 2006, the oil production will increase from 30 for 90 Mbopd.

Natural gas is another example of success. Production is expected to rise from the current 1.3 million m3/d to about 20 million m3/d by the end of 2008.

In order to reach these goals, Petrobras has invested in new infrastructure projects such as pipelines, processing plants and in the construction of a new port to support offshore operations. The company has also participated in research projects in partnership with the Federal University of Espirito Santo. These actions will consolidate a new cycle in the petroleum industry in Espirito Santo, the new deepwater frontier in Brazil.

A Little Bit of History

The performance of Petrobras in Espirito Santo State, located in southeastern Brazil, encompasses activities in the areas of the Espirito Santo Basin (onshore and offshore) and the north portion of the Campos Basin (offshore). The activities in the area initiated exactly 50 years ago (1957), with focus onshore, with the first discovery happening after a 10- year research period (1967). In 1968, in the Espirito Santo Basin, the first Brazilian offshore well was perforated (1-ESS- 01), in shallow waters (WD 47 m). Also after 10 years of work (1978), the Cacao Field appeared as the first offshore commercial discovery in the Espirito Santo Basin, at a water depth of 19 meters.

The onshore production initiated in 1973, reached the top production of 25 Mbopd in 1984, declining down to 9 Mbopd in 1998, when new fields were discovered in function of new technologies (seismic 3D). During this period, new wells were perforated in shallow waters (60 meters), leading to the discovery of two new non-associated gas fields: Cangoa (1988) and Peroa (1997).

In 1999, Petrobras started pursuing a new frontier in the area, perforating the first wildcat (1-ESS-90A) in deep waters. Hence, a new cycle begins.

In early 2001, the first commercial discovery took place in deep waters (Jubarte Field) in the north of the Campos Basin, followed by, in 2003, the discovery of light oil, also in deep waters, in the Espirito Santo Basin (Golfinho Field).
The Selection of Material to Avoid Fracture in Large Offshore Structure
Authors: Harrison J.D.
Published: October 2008

Due to stress concentrations and residual and erection stresses it is essential that the weldment regions be able to deform plastically without prior failure from the inevitable defects present in these regions. The paper outlines factors affecting fracture resistance and possible methods of material selection. A description is given of some standard tests for assessing brittle fracture resistance. It then describes the preferred approach which employs full thickness fracture mechanics tests of realistic weldments in which either the plane strain fracture toughness, K1c or the crack opening displacement, COD, is measured. From these an allowable defect size may be calculated. The selection procedure aims at ensuring that this is large; so large that the fabricator can be sure of avoiding larger defects either by careful attention to the control of the welding procedure or by non-destructive testing. The validity of the selection procedure is checked by carrying out large scale tests and also by correlations with actual service failures.

INTRODUCTION

The number of failures of fixed offshore structures due to brittle fracture which have been reported is relatively few. For example, of the 2,000 or so fixed platforms in the Gulf of Merico, it is understood that approximately 20 have failed from all causes including fire, collision, etc. Brittle fracture, however, was the cause of a significant number of these, particu1ar examples being given by Carter et al.1

As time progresses oil is being sought offshore in increasingly hostile environments, such as the North Sea. Two basic factors lead to an increased risk of fracture in such areas over the risk in areas exploited so far. These are greater water depths and lower air and sea temperatures. The first of these factors leads to the following, all of which themselves tend to increase the risk of fracture:The wish to use increased thicknesses.The wish to use higher strength materials at high design stresses.Larger welds leading to a lower ductility.Greater fabrication difficulties leading to greater risk of defects occurring.Increased difficulty of inspection to locate critical defects.

Factors 1, 2 and 3 tend to lower the transition temperature as will be seen later. This, combined with the reduction in operating temperature already referred to, clearly leads to an increased risk of fracture.

Any method of selecting materials for offshore applications must take account of the factors affecting resistance to fracture. The present paper outlines these factors, outlines the two main philosophies and the testing techniques for the selection of fracture resistant materials and describe in more detail a proposed selection procedure.
Wind Power: Wind Farms of the Northern Gulf of Mexico
Authors: Schellstede Herman J.
Published: October 2008

The Northern Gulf of Mexico has the potential to provide a substantial power source for the United States. Presently, alternative energy is being pursued by governmental agencies and the public. Many ideas being developed to provide energy are flawed due to basic financial inefficiency. A good source of energy is one that is low cost, has a direct method of conversion into useable energy and is plentiful.

Of course, wind has been employed in many facets of human development throughout recorded history. In many cases, the design evolution of machinery development is directly related to the research funds expended. In the last sixteen years, offshore wind energy farms have been constructed in European coastal waters. Wind turbines designed for land use were joined with marine technology to create the initial offshore wind energy farms.

Initial wind assessments of the Northern Gulf of Mexico suggest areas conducive to wind turbine power generation. The shallow waters of the Gulf of Mexico make economic sense for wind farm developers. This paper outlines a direct, efficient and predictable method for the development of offshore wind farms in the Northern Gulf of Mexico, combining technology found in the oil and gas industry with wind turbine technology. This marriage of technologies results in an economic method of providing electrical power to the mainland with an extremely environmentally-proven system.

This paper outlines the excellent power potential of the United States southern coastline and describes the basic steps which are being taken to provide power to the United States electrical grid.

Introduction

The offshore waters of the southern coastline of the United States have the potential to provide a sizeable degree of the power requirements required by the United States. The coastline has a far-reaching continental shelf, in some areas extending 80 miles while having water depths less than 150 feet.

General wind assessments have been conducted for many decades. After 1950, more specific data became available due to oil exploration and marine activities. Along the Gulf Coast, there are many ports, industrial areas, cities and activity near the shoreline. Many people live near the coastline of the Gulf of Mexico. Many of the states' coastlines are considered "noneconomic" with respect to the power generation by wind. Their offshore waters exhibit some of the best wind resources in the United States.

Each state bordering the Gulf of Mexico regulates its own territorial waters. With the exception of Texas, all the territorial waters extend three miles offshore. The Texas territorial waters extend 10.2 miles offshore. Water bottoms beyond the territorial limit are regulated by the Minerals Management Service. Based on the Texas territorial waters and the length of the coastline, Texas was chosen by offshore wind developer W.E.S.T. as its first choice for a wind farm site. A particular location has been chosen south of Galveston, Texas.
Industry/Government Relations in Offshore Resource Develop
Authors: Craven John P.
Published: October 2008

The paper compares the organization of the federal-industry relationship of a number of countries. This comparison is made against a hypothetical idealized nation which is organized to develop ocean resources in the best national interest. The paper demonstrates that of the nations examined, their ranking with respect to this idealized manager is as follows:Japan,Taiwan,Germany,France,Canada, andUnited States.

Federal support for ocean resource development in all nations falls into categories of support for (1) science, (2) technology, (3) systems acquisition and operation. In the idealized case, there is a measure of federal support in all three areas. This situation exists in Japan. In the most antithetical case, federal support is limited primarily to science and private industry and is prevented by law and custom from acting in concert to perform systems function. This situation exists in the United States.

INTRODUCTION

The description of any nation's endeavors to harvest the resources of the ocean is, at best, impressionistic involving, as it does, a myriad of bureaus and bureaucracies, corporations, and enterprises, research and development institutions, social and legal regimes and institutions, etc. A comparative description of a number of national endeavors to harvest the resources of the ocean must be equally impressionistic, since economic, social, political, legal and scientific regimes differ widely between different nations and are not therefore strictly comparable. Despite the inability to describe national organization for development of ocean resources or to compare them, the actual endeavors--private, national, and international-will, in fact, determine who develops the ocean resources, how they are developed, whether the resources are conserved or wasted, the distribution of economic wealth derived there from, etc. Some attempt, no matter how impressionistic, ought therefore to be made to assess and compare national endeavors as a guide to technology development, as a benchmark against which to measure changes or proposed changes in national policy, as a predictor of the trend and pace of ocean development, etc.

This paper undertakes to make such a comparative survey and to derive from it some measure of the relative pace and efficiency of the collective international effort to enjoy the resources of the ocean.

In order to accomplish this comparative study, an idealization will be employed-that of a hypothetical nation which is organized so that its government can perform as a system manager to optimize the process of exploring for and exploiting ocean resources the benefit of the nation. Against thisidealization, the organization of a spectrum of other nations can be compared and an assess transment can be made of their effectiveness in carrying out the system's goal.
Improvement of Fatigue Life of Steel Catenary Risers and Oil Offloading Lines in West Africa
Authors: Bertaso Daniel , Hutt Graham , Wang Jue , Tews Paul
Published: October 2008

This paper describes a study of the methods for improving fatigue life of girth welds for applications in the demanding environment of West Africa such as offshore Oil Off-loading Lines (OOL's) and Steel Catenary Risers (SCR's).

Investigations concerned the various methods for improvement of the fatigue life including root and cap grinding and internal root re-melting.

The paper also describes the use of laser triangulation as a mean to verify root profile before and after improvement.

Introduction

Fatigue based designs and the need to deliver high performance welds are now common features of the flowline and riser systems required for the exploitation of the deep water reserves.

Such requirements typically apply to steel catenary risers, oil off-loading lines and increasingly, as a result of the mitigation measures needed for flowlines that are subject to pressure and temperature fluctuations (e.g. where there is a risk of lateral buckling).

The consequence of such designs is the need for fabrication methods and girth welding procedures which satisfy very demanding fatigue performance targets while offering acceptable levels of productivity.

Recent industry experience has demonstrated that the some existing welding methods such as pulsed GMAW and GTAW are able to deliver results that exceed previous expectation for single sided welds but only when used with great care. Unfortunately this enhanced performance has only been possible by implementing very stringent control measures on weld geometry and allowable defects these in turn dictate requirements that are very close to the capability limit of the contributory processes i.e. pipe production accuracy, weld reproducibility and NDT system capability.

The criticality is clearly demonstrated by reference to the figure 1 which shows that even a very small flaw (micro-fissure) can be implicated in fatigue crack initiation. In this example of a manually welded root in 28mm thick c-steel, the undetected cold lap had an initial height in the order of 100 micrometres.

Objectives

Based on the foregoing considerations, the author's Company initiated a programme of work to investigate fatigue life improvement techniques that could be used to complement existing high productivity welding methods. The objectives were to identify methods that could be used to be maintain the high performance but with greater repeatability and, ideally, with the relaxation of some of the controlling parameters.
Draft Contribution to Future Guidelines for Licensing of CO2 Storage In Saline Formations and Depleted Hydrocarbon Reservoirs
Authors: Groenenberg Heleen , Carpenter Mike , Flach Todd Allyn , Zink-Jørgensen Kim , Schröder Peter , Beck Brendan , Christensen Nils-Peter , Chatwick Andy , Lescanne Marc , Aimard Nicolas
Published: October 2008

In January 2008 the European Commission proposed a directive on the geological storage of CO2 in the EU. Simultaneous to the development of the directive by the EC, the CO2ReMoVe project, funded by FP6 and industry, wrote a Draft Contribution to Future Guidelines for licensing of CO2 storage in saline reservoirs and depleted hydrocarbon reservoirs. This document contains detailed checklists for operators and authorities in each of the stages of a licencing procedure for a CO2 storage operation. The draft guidelines will be updated as results from monitoring ongoing CO2 storage operations become available. They may serve as a contribution to the regulation of CO2 storage anywhere in the world, and may be also be of use in evaluating the EU directive in the future.

Introduction

The geological storage of CO2 provides a key element in mitigating CO2 emissions and contributing to the achievement of Kyoto (and successor) targets in a world where economic stability will depend on fossil fuels for the next several decades. The first step towards Europe's goal of becoming a hydrogen economy requires the manufacture of hydrogen from fossil fuels. This can potentially be done cost-effectively on a large scale without significantly reduced GHG emissions, if the resultant CO2 can be securely stored in geological formations.

Europe has invested large research efforts in CO2 geological storage monitoring in a number of storage scenarios, gaining experience with industrial-scale projects (Sleipner, Weyburn), and smaller-scale pilot projects (Ketzin, K12B, Kaniov). Two new industrial-scale geological storage projects (In Salah and Snohvit) now provide the opportunity to build on this work. For CO2 storage to qualify in Emission Trading Schemes, R&D efforts are required to develop a sound basis for monitoring and verification. This will provide the assurance of long-term storage security and establish consistent site certification guidelines for policy makers, regulators and industry.
ACG Topsides Design and Fabrication
Authors: Kearney Carroll Lee , James Mike , Nethercott Tim , Tate Geoff
Published: October 2008

The ACG Project concept basis was to deliver as few platforms with as many wellslots as possible, resulting in the delivery of four new drilling topsides facilities having a total weight of the order of 15,500 tonnes each, plus two injection support platforms weighing approximately 13,000 tonnes each. Integrated topsides for this size had never been fabricated in Azerbaijan.

The project was also challenged due to limited and out-of-date fabrication infrastructure and no in-country proven fabrication contractor capability for such topsides construction.

The solution was to establish a topsides production line approach to delivery, with the design being cloned from deck to deck underpinned by simplistic layouts for drilling and injection support topsides, respectively. Further, the installation of these decks would be via floatover installation method, thereby allowing the maximum amount of onshore commissioning with a minimum of offshore commissioning. All topsides fabrication would occur at two in-country fabrication yards, with the exception of the drilling facilities and the living quarters.

This paper describes the development of the topsides layouts, supporting engineering design, fabrication yard upgrades, cloning benefits and decisions associated with where and how fabrication could optimally be achieved.

The ACG topsides production line was successfully established and six topsides have been delivered offshore since start of fabrication in November 2001. As a result, similar production lines are being established on other developments.

The information in the paper will be of use to others who have similar large field offshore developments where full cycle delivery - from start of engineering design to start of production - can be optimised.

The production line approach, underpinned by standardisation of design, fabrication processes and people, proved capable of delivering deck-on-deck reductions in cost and schedule. The delivery can be improved further through the rigorous use of lessons learned feedback.

This project demonstrates the benefits of developing innovative solutions to overcome specific problems. These solutions were relevant in a part of the world that has not traditionally delivered facilities to shareholder standards.

Introduction

The ACG Full Field Development (FFD) Project began in 1997, but, due to a variety of economic and geopolitical reasons, the first phase of project sanction did not occur until September 2001. The chosen offshore development strategy involved three phases of incremental development - two large fixed offshore platforms for each phase (see Figure 1 at end of paper).
The Application of Similarity and Repeatability Premises in a FPSO Conversion
Authors: Barbosa Carlos Bartolomeu Bastos , Klein Mario Nigri , Machado Marco Tulio Pereira , dos Santos Aldemir Bonfim , Filho Joper Andrade , Guedes Fernando Pedrosa
Published: October 2008

This paper aims at discussing the main advantages of repeating a FPSO Project for different oil fields developed by PETROBRAS. It will also be discussed the main aspects which shall be considered during projects based on oil tankers conversion into FPSOs, emphasizing the topics that can influence the overall progress of the works.

Contractual requirements have been highlighted, such as minimum Brazilian national content, engineering scope of work, type of contracting, standardization of systems, construction using topside modules concept and some other points. Special attention must be given to the material and piping specification, as well as to the versions of applicable Rules and Regulations and Classification Society requirements. Case study based on the FPSO PETROBRAS 50 (P-50) and its " younger sister?? PETROBRAS 54 (P-54) project is presented, giving special attention to the Topsides and Marine systems, as well as to hull conversion works and related technical documentation. All the advantages obtained from the similarity and repeatability between the projects have been discussed, showing how they contributed to reduce the delivery time of the Unit.

Other aspects adopted in such projects will be presented herein, such as: integrated team between the Operation and C&A (Construction & Assembling). Also, a focus on HSE (Healthy, Safety and Environment) during the construction and assembling phase will be presented.

Introduction

The development plan of an oil production field starts during the conception phase. During this phase, the type of the Unit to be installed and the construction schedule are defined. If the Unit to be adopted is a FPSO (Floating, Production, Storage and Offloading), 02 (two) options are possible: a tanker conversion or a new built hull.

The type of Unit to be adopted for the field exploitation depends mainly on a technical-economic analysis, which is developed by PETROBRAS. At this moment, some alternatives are evaluated and considered, such as the type of hull (converted vessel into a FPSO, FPSO with new hull, converted Semi-Submersible, new SS), capacity of the production plant, facilities, etc. According to the economic-financial return for each option and taken into account the possibilities at the moment (availability of vessels for conversion, for instance), the chosen alternative will be the one that presents the best results.

In general, the technical teams prefer customized projects for production Units. It means that the Unit must be a " Taylor made?? project, built specifically for each field. However, in some situations, this is not the best alternative to be followed. In this way, the premises of repeatability and similarity are an optimized and very attractive decision that will result in a highest financial gain.
Effectiveness of Polyethylene Helical Strakes in Suppressing VIV Responses After Sustaining High Roller Load Deformation During S-lay Installation
Authors: Boubenider Rafik , Alptunaer Kaya , Fourchy Paul J. , de Wilde Jaap
Published: October 2008

Helical strakes are an important Vortex Induced Vibration (VIV) suppression device for Steel Catenary Risers (SCR's). This paper presents the results of two sets of hydrodynamic tests performed at MARIN, on a 12?? pipe fitted with 16D Helical Polyethylene strakes. The first set of tests established the suppression efficiency of the strakes for the Intact Configuration (no deformation). The second set of tests established the performance of the same strakes after undergoing a roller test in which the fins and the body of the strakes have sustained permanent deformations due to a simulated high contact load on the roller of a stinger during an S-lay installation. The type of permanent deformations sustained by the strakes can be described as bulging of the strake body, and permanent folding of the fins. Both configurations of the strakes (Intact and Deformed) were tested at high and low Reynolds numbers (velocities of 2.5 m/s and 0.5 m/s) and at different reduced velocities Vr. The results show that for the Deformed strakes configuration, there was no appreciable decrease in the VIV suppression efficiency of the strakes from a design consideration. The test results indicated that both Intact and Deformed strakes were at least 90% efficient in suppressing VIV. Therefore, based on the tests reported in this paper, the Polyethylene strakes were deemed acceptable to use on the SCR's even when using the S-Lay installation method.
Extending the Use of Conventional Construction Technology for the Installation of Subsea Production Facilities in Deep Water
Authors: Vennemann Olav , Frazer Ian , Tornqvist Rikard
Published: October 2008

It is clear that the offshore industry is striving to develop fields in deeper and deeper water and that subsea production is a key element in this development. This then leads to the question of what is the most efficient method of installing subsea production equipment in very deep water. This paper will address the issues associated with using conventional lifting technology based on steel wire rope for deep water applications. The new deep water construction ships being brought into operation have conventional lifting equipment based on steel wire rope. The requirement to be able to handle loads in excess of 300 t in great water depths leads to the need for large diameter multi-strand ropes with low spin characteristics. The long term behaviour of these ropes particularly in applications which require the use of heave compensator is uncertain due to the lack of any suitable test data. This paper will describe a full scale testing program to determine the fatigue performance of large diameter steel wire rope, including the design and building of a new testing machine, together with a summary of the results and the impact the results have on installation operations.

Background

On many of new deep water construction vessels coming into the industry, large wire ropes of 109 mm diameter are used for deepwater installation tasks and A&R activities. Some of these ropes are multi-strand ropes with low torque characteristics designed to be used in a single-fall arrangement. The ropes are subjected to bending when passing over a number of sheaves before overboarding the vessel. In many of the construction vessels, such as the Polar Queen (see Figure 1), an additional Heave Compensator (HC) is included into the deepwater installation system. This will potentially increase the number of bend cycles of the rope significantly depending on the duration of the use of the HC.

A literature research indicated that very little data is available on bending fatigue performance of large diameter ropes under load. Several sources were found presenting bending fatigue results of smaller diameters (Gibson 1980, Potts & Chaplin 1990, Müller 1961) but very little experience was documented on ropes over 90mm diameter. Further investigations showed that no such test facility was available to perform bending fatigue tests on large diameter ropes of 109 mm.

Based on these findings, it was decided to build a test rig to perform cyclic bending fatigue tests which would simulate the severe conditions experienced by the rope when used for subsea handling tasks and to perform cycling bending fatigue tests. These tests were accompanied by NDT tests to document the rope deterioration during the bending fatigue performance.