bluuebunny/crossref_metadata_2025 huggingface dataset:
Explosives Return To Marine Seismic Surveying
Authors: Savit Carl H.
Published: October 2008

Small explosive charges are now being used as seismic reflection and refraction sources. Half-pound charges of nitrocarbonitrate detonated at a depth of 40 or more feet are found to be the seismic equivalent of 150 1b at venting depth. Bubble effects are removed in digital computer processing. High repetition rates permit resolution equivalent to that of non explosives while achieving the maximum penetration provided by explosives.

Seismic exploration was conceived more than a half century ago with the expression of the basic idea that sound waves will-travel in a different manner in different kinds of rocks. Reginald Fessenden in his 1916 patent proposed to generate the sound waves by means of an electric oscillator. His oscillator and his listening devices were to be placed in water-filled holes in the ground.

It soon became clear that the primitive oscillators, microphones, and amplification systems of the 1920 era were incapable of achieving penetrations through the earth of more than a few tens of feet. Not until Ludger Mintrop and John C. Karcher in the early 1920's substituted explosive charges for the electric oscillator did seismic exploration become practical.

When seismic exploration moved to sea in the late 1940's and early 1950's, it naturally took along the explosive sound sources which had been so successful on land.

Unfortunately at sea; the reflection seismologist was faced with an apparently irreconcilable dilemma. He had, in the years of land work, learned through experience that his explosive charges were most effective when well tamped. He had drilled holes in the earth, placed charges in the bottoms of the holes, and filled the holes with water or mud to serve as a tamp or reaction mass. If he did not have enough tamping, he found that his charge produced a far smaller seismic wave than that which he could expect with adequate tamping. At sea, however, when he put his charges downdeep enough so that the water above the charge served as an appropriate tamp, he found an unpleasant side effect.

When an explosive is detonated, the explosive material changes abruptly to a gas at high temperature and pressure. If the detonation takes place deep under water, these gaseous explosive products expand rapidly to form a gas bubble of increasing diameter. Because of inertia, expansion continues after the gas pressure inside the bubble has fallen below that of the surrounding water. Cooling of the gas enhances the pressure contrast. When the expansion finally stops, conditions in and near the bubble are unstable. The water pressure around the bubble is substantially greater than the gas pressure inside the bubble. The bubble collapses with increasing speed as the water rushes inward. The result is another sharp acoustic pulse, frequently one more powerful than the initial detonation pulse.
Roncador Field Development: An Overview
Authors: Garcia A.L. , Bocos M.D. , Mihaguti M.K.
Published: October 2008

Roncador, a giant field in the northern area of Campos Basin, was discovered in October 1996 at water depths that range from 1,500 to 2,000 m. Its development was planned to perform parallel investments for the appraisal phase and the first development phase instead of a more traditional sequential strategy. This challenging field started production in January 1999 and has been producing since then through a pilot system, the FPSO Seillean, installed over de RJS-436 well at 1,853 meters of water depth - a new world record. The permanent production system for Phase 1 is scheduled to start in the first half of 2000 with the arrival of the P-36 platform (ex-Spirit of Columbus) and the FSO P-47. This paper presents the planning for the overall field exploitation and the final concept for the field development, emphasizing the first phase.

The concept of the first phase represents the conclusion of the analyses and technical studies related to the exploitation of an oilfield located in ultra-deep waters. The critical path of project schedule, the management of both the uncertainties of the reservoir and the ultra-deep water technological development and also the commitments assumed for the production start-up, add to this project some unusual and very challenging characteristics. Roncador field development success proved the commercial and technological feasibility, in large scale, for oilfields located in water as deep as 2,000 m, reaching the current goal for PROCAP-2000, Petrobras' deepwater research program. The achievement of this goal will allow Petrobras to set a new challenge - the 3,000 m water depth limit.

Introduction

Roncador field was discovered in October 1996 by the wildcat RJS-436. The "132 square kilometers giant field" lies 125 kilometers off the coast of Rio de Janeiro, at water depths that range from 1,500 to 2,000 meters (figure 1). The size of the field, the good quality of the crude and the concurrent benefits for the downstream, together with the economic results of the project, led the Company to adopt a fast track development plan.

In January 1998 another wildcat, RJS-513, confirmed the extension of the reservoir and the existence of oil in the southwestern portion of the reservoir. The first well presented the existence of 31°API oil and the second an 18°API oil. Immediately afterwards, Petrobras began the appraisal of the reservoir, drilling four other wells. Even though the area was not yet fully appraised, because of its extension, these four wells plus the initial information coming from the first two production wells drilled so far, confirmed the predictions and rised the field reserves to the current volumes, estimated at 3.3 billion barrels (boe). New wells have been planned in order to appraise the reservoir southwards and eastwards to provide more information for the overall development plan. The exploitation of Roncador field is planned to be developed in three phases (figure 2).
FPSO Integrity; Structural Monitoring of Glas Dowr
Authors: van den Boom Henk , Krekel Max , Aalberts Pieter
Published: October 2008

The objective of the Joint Industry project 'FPSO Integrity' is to provide insight in the fatigue loading of FPSO's and the accuracy and validity of computational models. The results should contribute to reliable life time prediction and site assessment studies for this relative new concept of production.

Within the frame work of this JIP, 'Glas Dowr', a new build double hull FPSO operated by Bluewater for Amerada Hess at the Durward and Dauntless fields in the North Sea, has been instrumented extensively.

The objective of the instrumentation was to measure sufficient signals to derive the fatigue loading on the vessel. The dedicated monitoring system comprised the instrumentation of two cross sections of the vessel with strain gauges, pressure transducers and wave height radar's. Also the deck and the turret were equipped with strain gauges. Both the wave induced motions and the low frequency positions and orientation of the vessel was recorded. For the analysis of the measured signals the wind, wave and current conditions have been recorded as well as the vessel parameters such as draft, trim and tank loads. Data from the Glas Dowr has been collected from October 1, 1997 to 1 August 1999. The data has been subjected to long term statistical analysis and for selected periods to more detailed spectral and statistical analysis as well as rain flow counts.

The results have been used for validation of existing fatigue load calculation methods used by five classification societies and for the development of new fatigue load prediction software.

INTRODUCTION

For design, engineering and site assessment of Floating Production Storage and Offloading (FPSO) units, a reliable fatigue life prediction is essential. A computational model of the fatigue life of an FPSO comprises a description of the environment, a model of the fatigue loads and a model of the fatigue response.

As the operation of an FPSO is completely different from a trading tanker, in 1996 a Joint Industry project named FPSO Integrity was initiated to provide insight in the fatigue loading of FPSO's and the accuracy and validity of computational models. The background, objectives and structure of the project are described in further detail in ref [1].

The FPSO Integrity JIP comprised four major tasks:Structural monitoring of FPSO 'Glas Dowr' operated by Bluewater for Amerada Hess on the Dauntless and Durward field in the North Sea.Analysis of the measured data to derive the fatigue loads on the vessel.Development of a fatigue load assessment method, which can be used for a fatigue lifetime prediction.Comparative Study on the existing fatigue analysis methods currently used by the five Classification Societies involved in the project.

As the ultimate goal of the project was not only development of new calculations procedures but also comparison against existing methods and real life data, the project demanded a strong input from all stakeholders in the FPSO industry.
Inclined Uplift Capacity of Suction Caissons in Sand
Authors: Deng W. , Carter J.P.
Published: October 2008

This paper presents results of a theoretical investigation of suction caissons installed in seabed deposits composed of dense sand and subjected to inclined uplift loading under fully drained conditions. Consideration is given to the effects of caisson embedment, load application point, load inclination angle, friction angle of the soil, dilatancy and the initial stress state, as defined by the value of K0. Simplified expressions for the inclined uplift capacity of suction caissons are developed, based on the results of the finite element study.

Introduction

Suction caissons have been employed with success as foundations for large gravity platforms and as anchors for floating structures in areas such as the North Sea, the Gulf of Mexico and the North-West Shelf of Western Australia. Previous studies of the uplift capacity of a suction caisson have mainly concentrated on cases where the caissons are embedded in cohesive soils, i.e., where the undrained condition is of prime importance.

Erbrich4 investigated the vertical load carrying capacity of a suction caisson in a dense silica sand profile with clay layers using the commercial finite element package ABAQUS. His work appears to be the first published numerical investigation of the uplift capacity of a suction caisson embedded in sand. Soon after, Bye et al1 described the design analyses of the Europipe 16/11E and Sleipner T foundations, which were also embedded in dense sand. Analyses of the uplift capacity of the caissons were performed using a slip surface-type model, and an attempt was made to incorporate the effects of sand dilatancy and the accumulation and dissipation of pore water pressure. Static pullout capacities measured in field tests were also reported and compared to predictions based on classical bearing capacity theory. It is evident from this study that sand dilatancy, as well as the drainage characteristics of the soil, together with the duration of the loading, are dominant factors in determining the uplift capacity.

The increased use of suction caissons in sandy soils defines a pressing need to develop reliable methods for predicting their capacity, particularly when they are subjected to inclined uplift loading.

In the study described in this paper, a theoretical investigation has been carried out of suction caissons subjected to inclined uplift loading for cases where the seabed soil is dense sand. It is assumed that the sand behaves in a fully drained manner under the application of the caisson loads. The results should therefore be applicable to cases of sustained loading of caissons in sand.

The typical problem considered in the study is illustrated in Fig. 1. The suction caisson is assumed to be cylindrical with an overall diameter d and an embedded length L. It is assumed that an inclined uplift force is applied at the caisson wall by a chain attached to a lug located at a depth D, and the force is applied at an angle ?a to the horizontal plane. In practice, it is usual for the loading to be applied through a chain fixed to the side of the caisson.
Measurement and Analysis of Ice Forces on Cook Inlet structures
Authors: Blenkarn K.A.
Published: October 2008

The paper presents results of ice force measurements made in Cook Inlet, Alaska, over a number of years. Data include measurements made on a specially instrumented test pile as well as strain gauge records from a number of different platforms.

Ice force values are interpreted within the framework of a conceptual model corresponding to visual observations of the behavior of ice impinging on structures. Forces are related to ice conditions and related meteorological influences. Correlations are made between ice thicknesses measured in Cook Inlet and published ice growth formulas. Such correlation provides a basis for prediction of expected extreme thicknesses on the basis of historical weather records. Consideration is also given to the effect of ice temperature upon ice forces on structures.

Force records show details of the dynamic response of structures to ice loading. Conclusions drawn from study of the recorded dynamics are summarized.

From extensive observations of ice conditions in the Cook Inlet area, a variety of ice phenomena are described and analyzed in relation to their potential effect upon structures. With all such phenomena considered, the paper develops predictions of maximum ice loading to be anticipated.

INTRODUCTION

Subsequent to drilling of the first discovery wells in 1962, the upper segment of Cook Inlet, Alaska has been the site of an intensive offshore oil development activity. The most notable feature of the offshore development in this area has been the design and construction of 14 large offshore structures capable of resisting the extreme environment. Although the region is subarctic, Cook Inlet can develop a substantial ice cover. The potential destructiveness of the ice is magnified by a tide range of more than 20 feet and the accompanying 6-knot current.

In the absence of design information applicable to the conditions of Cook Inlet, an extensive effort was devoted to a study of the region and to determination of ice forces. This effort was primarily executed by two groups of oil companies, Pan American Petroleum Corporation being operator for one of these groups. The in-field work involved extensive reconnaissance testing of ice as well as the direct measurement of forces on several types of structures installed in the Inlet. A part of this activity has been described (Refs. 1, 2 and 3), but results are presented only in a general way. The purpose of the present paper is to summarize specifically the results of ice force measurements and to relate these force measurements to ice conditions. In addition, attention is devoted to study of the dynamic response of structures to the action of sea ice floes.

NATURE OF COOK INLET ICE

Most of the ice cover which forms on Cook Inlet has properties similar to ice Observed in other parts of the world. In standard ice observation terms, the seasonal ice cover on Cook Inlet is thin, first-year ice. The floes of the ice cover vary from medium to large floes, individual floes more than one-quarter mile across being common.
Rock Salinity Variations as Earth Stress Indicators
Authors: Overton Harold L.
Published: October 2008

INTRODUCTION

Shales have recently been shown to be sensitive to both fluid and solid transmitted pressures, in the earth. l The salinity principle has shown that shale porosity, fluid pressure, rock stress and water salinity exist in mechanical and thermal equilibrium. The following two equations have been shown to be applicable whenever marine sands and shales are subject to variations in salinity gradients.

(available in full paper)

The porosity ?sh is directly related to the effective pore pressure, ?-P, which is the difference between solid and fluid transmitted stresses. The constant c depends upon geologic time and may be found in Ref. 1. It also may be noted on a graph of shale porosity or sand salinity whenever a profile of these parameters is available down to 8, OOO-ft depth. In general, c is 6 × 10−5/ft, for middle Pliocene, but may be solved directly from the SP curve.

(available in full paper)

Hence, the SP and density logs may be used to corroborate each other when viewed kiloscopically [on a kilometer scale]. In general, these three equations can be used to locate faults, unconformities and zones of high pressure. Pressures may be accurately calculated from Eq. 2 whenever the density log is run over the entire length of the wellbore. In the following equation a simple method uses the two depths at which similar shale densities are found.

(available in full paper)

In Eq,. 4, G fluid is the weight in Ib/gal of the average salt water gradient at any depth D. .6D is the difference between depths at which the shale densities are equivalent; G is the pore pressure gradient encountered by the drill.

Since all parameters in Eqs. 2 and 3 are now measurable, with the exception of ?; the rock stress is now calculable. However, since there generally is no way by which to check the calculations, the author will restrict the analysis to more practical evaluations. Quick checks on rock stress calculations are possible with casing collapse, sand fracturing and thrust, faulting. Sand fracturing will be reserved for I a subsequent paper.

FAULT STRESSES

Fig. 1 shows a salinity analysis where a review of the introductory statements is possible. The following features are plainly visible in Fig. 1.The critical compaction depth for Gulf Coast shales is 3)100-ft or less. Shales bind salt readily below that depth.Sand salinity varies quite uniformly, according to Eg. 3, on a depth profile with the exception of some faulting near 7, 000 ft. At this depth) salinity decreases in the downthrown block [in tension], while compression causes salinity increases in the up-thrown block.The boundary between Pleistocene and Pliocene is readily apparent at 5) 500 ft. This unconformity yields a salinity contrast due to a possible difference in compaction between the two intervals.Overpressure may be located and calculated at the depths of lowest water salinity. Both acoustic travel time and shale porosity yield similar pressure gradients.The shale-compaction coefficient of 4.96 × 10-5/ft indicates that the zone below 4, 000 ft is upper P1iocene. l
Subsea Tree Changeout with a Light Subsea-Well-Intervention Vessel
Authors: McGennis Eamonn
Published: October 2008

There are currently over six hundred active subsea wells in the United Kingdom Continental Shelf (UKCS) and with this extensive inventory of operational wells a need has developed for intervention and maintenance services for the actual subsea trees used on these wells. In certain cases the maintenance work required on subsea trees can be undertaken in situ on the seabed by either Remove Operated Vehicles (ROV) or by saturation divers. There are many cases however where more complex tasks are required. In theses cases it can often prove more effective to recover the trees to surface. This will reduce the risks and costs if an effective tree recovery procedure can be implemented.

As a result procedures have been developed for use from a Dynamically Positioned (DP) Well Services Vessel (WSV) (Ref. 1) and have been used successfully on twelve occasions in the UKCS. This activity includes seven tree changeout operations, three tree recoveries and two projects for tree deployment. This experience has shown that it is both cost effective and safe to temporally plug a producing well to recover the tree back to surface for maintenance. This paper will review the development of this subsea tree changeout procedure and how a WSV can effectively complete this complex operation.

The paper will outline the current procedure used for this operation and how it has been refined with recent experience. This experience was put to good use in June 2000 when a tree was recovered to deck for a maintenance operation. Once the tree was on deck it was recognised that it would have to be returned to shore for major work leaving a good producer shut in. To overcome this problem the WSV reconfigured a Water Injector (WI) tree on deck. The reconfigured WI tree was then run back in place of the production tree. This allowed the well to come back into production and so avoided an expensive loss of production from the well.

The flexibility and speed of the WSV solution offers significant advantages over the conventional rig based options. The WSV solution has proven to reduce risks and costs allowing work to be carried out that would otherwise be uneconomic. This is a technique that should allow many older fields remain profitable and in production.

Introduction

During routine inspection of producing subsea facilities in the Central North Sea (CNS) of the UKCS a major operating company became concerned with a particular technical aspect on one of the subsea production trees. To rectify the problem it was decided that there would be real advantages if the tree could be brought to surface for a detailed inspection and repair by the Original Equipment Manufacturer (OEM). As the work on the tree appeared straightforward it was estimated that the operations could be carried out on site.
Installation Method Evaluation of Export SCRs
Authors: Wang X. , Zhou X. , Ginnard A.J. , Sprot J.T.
Published: October 2008

The Banjo oil and Seahawk gas export risers are the first dynamic SCRs to be installed on truss spars and hosted by Jtubes. Each of the two truss spars, located at the Boomvang and Nansen fields in 3,440 ft and 3,670 ft of water depth, respectively, in the Gulf of Mexico, has one oil and one gas export SCR. This paper presents the detailed, post-lay, SCR installation method evaluations for these field developments, from vessel requirement, SCR pick-up, keelhaul under the spar mooring, positioning to J-tube bell-mouth, and pull-in to its hang-off position.

Introduction

The export systems of Boomvang and Nansen fields in East Breaks Block EB643 at 3,440 ft of water depth and Block EB602 at 3,670 ft of water depth, respectively, consist of one oil export line and one gas export line for each field. A truss spars at each field serves as the surface floating production system. SCRs (Steel Catenary Risers) connect the subsea pipelines to the topsides. Cantilevered J-tubes for the SCRs serve the function commonly accomplished by a flexjoint or stress joint, mitigating the bending moment at the support of the SCRs. All four SCRs employ such cantilevered J-tubes that extend from the bottom of the hard tank at elevation (-) 160 ft to the keel-tank with a bell-mouth exit at elevation (-) 507 ft. The SCRs, extended from the bottom of the hard tank where the J-tube ended and up through the moon-pool, hangoff at elevation (+) 51 ft with anchor flanges supported by split collars. All SCRs have a nominal departure angle of 14 degrees as their host J-tubes. For the Boomvang spar, the oil and gas export SCRs use 16-inch nominal diameter pipe with 0.812-inch wall thickness and 18-inch nominal diameter pipe with 1-inch wall thickness, respectively. For the Nansen spar, both the oil and gas export SCRs employ 12-inch nominal diameter pipe with 0.562-inch wall thickness. The wall thicknesses for the SCRs are controlled by the reel-lay method not mechanical integrity. The reel-lay method is selected for the pipe-laying of all four export pipelines and their SCRs. All SCR pipes are grade X65 seamless. The J-tube insider diameters are 19-inch, 23-inch, and 25-inch for the 12-inch, 16-inch, and 18-inch SCRs, respectively.

Due to the field development schedule, all four export SCRs will be laid prior to the arrival of the Boomvang and Nansen spars. After the spars are placed in position, mooring lines attached, the SCRs are then picked up and installed utilizing construction vessels. Two technical challenges exist in the installation of these SCRs. First, each SCR will need to be picked up by the support vessel, keelhauled through three spar mooring lines to reach the SCR hang-off side of the spar. Second, the SCRs on the truss spars are hosted by J-tubes, which extends from the bottom of the hard tank to the keel tank.
Reliability and Safety of Pipeline Laying by Reeling Technology in Deepwater
Authors: Kershenbaum Naum
Published: October 2008

The paper presents the results of reeling pipeline stresses and strains amplification investigation and describes the practical proved method to suppress the phenomenon, prevent a failure, and provide pipelay reliability and safety.

Advantages of pipeline laying by reeling are the cause of worldwide use of this method for pipe diameters up to 16-inch and even more in a future.

Some time ago there were several occurrences of pipe rupture during reeling in area of pipe properties changes (wall thickness or pipe grade) from previous joint to the next one. The rupture surface inspections have shown significant and unusual overstress in the area as a result of stress / strain reallocation. Stress / strain amplification occurs at any joint with different properties along the pipeline on a reel drum and especially when the connection is leaving a drum surface. The pipeline reeling failures have caused companies significant losses. It is suggested an amplification suppression method by utilizing a special form transition joint between different properties adjacent joints. The presented procedure allows control of the transition joint stress / strain values depending upon joint geometrical and steel property variations. The analysis is based on curvilinear beam non-linear stress - strain consideration and presented in spreadsheet form.

The above method has been successfully used during BPX Pompano Phase II Project and Pennzoil Flowline and Riser Project.

Introduction

Modern subsea pipeline construction uses the most cost-effective methods of installation. The pipelay by reeling technology is one of them providing the construction, acceptable cost and terms. This technology has been used with success for a relatively long time. The method and equipment are adapted now to lay pipeline up-to 16 inches in diameter and probably will be used for pipe-in-pipe assembly installation.

Reeling technology is associated with a high level of bending strain, which is often just slightly below pipe shell buckling strain values.

The approach is generally acceptable because there is a good reeled pipe axis curvature. Indeed, the curvature is maintained by the reel drum radius magnitude. That is correct until the reeled pipe has unchangeable properties: beam bending stiffness and pipe's moment-to-curvature non-linear characteristic values. If there is any changes in the reeled pipe properties then, the bent around reel drum stiffer pipe section generates the certain moment value, which could not be acceptable for the weaker pipe section being the extension of the stiffer pipe.
Diana / Hoover Installation: Overview
Authors: Arthur Timothy T. , Meier Jayme K.
Published: October 2008

This paper provides an overview of the ExxonMobil Diana/Hoover offshore installation, including both surface and subsea components in a record water depth of 4,850 feet.

The use of equipment advancements and industry firsts are presented together with a description of the organization and management of the project. The paper concludes with an overview of performance results and lessons learned.

Installation Overview

The installation of a Deep Draft Caisson Vessel (DDCV) drilling and production facility with related subsea pipelines and components in record water depths presented unique installation challenges, which required technology development, equipment advancements and a novel execution approach. Some of the "Industry Firsts" achieved were 1) the heaviest lifts onto a floating structure in open waters, 2) the deepest and largest Steel Catenary Risers (SCRs) installed 3) the largest mooring system installation, and 4) the heaviest lifts onto any type structure in the Gulf of Mexico.

The equipment advancements associated with the project included mooring system handling equipment, a two station J-Lay tower that installed the majority of the flowlines and SCRs, and a "long tether" pipeline touchdown monitoring ROV located on the pipelay vessel.

The 950+ man-year installation mostly occurred during the winter months of 1999/2000 in an area that routinely experiences high velocity eddy currents. These environmental conditions presented safety and operational issues that challenged the Diana/Hoover Construction vessels, which were among the largest in the world.

The execution approach was focused on selection of the most qualified Contractors working predominately under a risk sharing contract structure. A co-located integrated project team organization with common priorities was utilized to manage the offshore execution program. The team was expected to make decisions that were considered in the best interest of ExxonMobil (EM), the individual contractors and the overall project.

The components installed as part of this project are shown in Figure 1. The following sections provide additional detail regarding the platform and subsea installations.

Surface Components

The surface components installed included the DDCV hull, lower and upper deck modules, and various other packages that were lifted into place offshore. This work occurred over a 70 day period, with the Saipem S-7000, the world's largest semi-submersible crane vessel (SSCV), being utilized as the primary construction vessel.

DDCV Hull

The DDCV hull (Fig. 2) was 705 feet long, 122 feet in diameter and weighed 35,000 tons. It was fabricated in two sections in Pori, Finland, and each section was dry transported by heavy lift vessel to Corpus Christi, Texas. The two hull sections were joined in Corpus Christi and wet towed to site in the horizontal configuration. Once the hull arrived offshore it was prepared for upending and mooring.
A Probe for Characterization of Deepwater Commercial Sands
Authors: Cruickshank M.J. , Knapp R.H.
Published: October 2008

This paper describes a new tool to measure, in situ, the engineering and environmental characteristics of unconsolidated seabed materials, particularly carbonate tropical sands, as much as 15 meters thick in water depths to a maximum of 20 meters from a small unanchored vessel. The initial prototype uses a pneumatic hammer to drive a video camera probe into the seabed. During penetration, the tool, which is shaped like a wood chisel, slices through the unconsolidated material leaving a virtually undisturbed face exposed to the camera. A selection of other physical, chemical and electrical sensors can be used to measure properties and composition of the sediments. In comparison with traditional sampling technology, it is anticipated that the cost of data acquisition may be reduced by an order of magnitude with this system. Although conceived for the characterization of offshore carbonate sand deposits, this unique tool will be adaptable to the characterization of other sites both on land and in the seabed.

INTRODUCTION

Sandy beaches in the tropical Pacific are, for the most part, derived from the erosion products of coral reefs surrounding islands. The sand budget is limited to the production of the reef corals and, in many places, the removal of beaches by storms or by commercial entities for the construction of infrastructure has resulted in serious degradation of the beaches with no hope of timely replenishment by natural means (Cruickshank, 1997). Shoreline loss in the State of Hawaii, and particularly O'ahu, is presently occurring at a significant rate. In 1997, "massive degradation" of Oahu's coast was reported with about 24% of the island's original 71 miles of sandy beach "either gone or so narrowed that at high tide it is unusable" (HA, 1997). It has now become paramount to find sources of sand for beach replenishment and maintenance that will be both environmentally and economically sustainable.

Recent discoveries by the United States Geological Survey (USGS) and others have indicated a potentially very large source of clean sand on ancient beaches between 70 and 130 meters deep. These beaches appear to be part of the Makua Shelf system formed some 40,000 years ago. Of particular interest is that they are outside the reef at depths below the impacts of storm waves, and the removal of sand should not affect the present shoreline in any way. Furthermore, it now appears that these deep water beaches just beyond the reef cliff might be found Pacific wide and there are no inhabited islands in the Pacific Basin that do not suffer from the same problems as O'ahu. This depth is considerably greater than normally anticipated and the characterization of the deposits using traditional vibracoring tools has been shown to be time consuming and expensive.
Design Correlation of Elastic Behavior and Static Strength of Zero Eccentricity T, Y, and K Tubular Joints
Authors: Graff William J.
Published: October 2008

The stress state on the tube surface adjacent to the weld line in the chord member of a tubular joint is very complex. Over the past decade investigations have shown however that the most critical stress component is the circumferential stress directed around the chord. This stress is very high immediately next to the weld toe and decreases rapidly going away from this point about the circumference. The location of the origin for this stress axis depends on the kind of joint and the type of loading. This paper analyzes experimental data from several investigations to show the location of the circumferential axis for different loading arrangements and to present a method of estimating whether a proposed tubular joint Will be within or beyond the elastic limit stress at the critical point on this axis.

INTRODUCTION

This paper is an analysis of the experimental work contained in several investigations to combine and interpret the results in a form more usable for design purposes. Within the past five years there her e been several outstanding experimental studies of tubular joints (1, 2, 3). In the five year period before that there were many investigations, several (4, 5, 6) of which seemingly would combine with and support the more recent studies. However, the most perplexing aspect of attempting to correlate these data is the unending variability of various geometrical details and loading arrangements of the joints tested. In trying to reach generalizations, it is as if each individual test were a special case both in geometry and load.

The industrial community is fortunate in that from time to time certain investigators have such dedication and interest in their work that nothing is omitted from the completeness of their reporting. Such is true of References 2 and 3 and the preliminary reports (7, 8, 9) associated with them. Even a modest attempt at testing a tubular joint (10) is sufficient to point up the degree of expertise and care required to obtain meaningful information. The thorough and systematic nature of the data in the reports just mentioned permitted their use extensively in the analysis which follows.

THE TUBULAR JOINT

A welded tubular joint is that portion of a structure where circular cylindrical tubesare joined by fusion welding of the cross section of one or more tubes (called braces) to the undisturbed exterior surface of the other tube (called the chord). In structural applications the brace ordinarily does not penetrate the chord wall.

The stresses in tubular joints, as in most structural parts, are not simple stresses, such as tension, compression, bending or shear, but are combined stresses that act in more than one direction. Determination of the stress state in a tubular joint is quite complex and a satisfactory analysis for practical work has yet to be developed, although one method (11) recently published indicates a useful approach.
Flexible Pipe for Ultra-Deepwater Applications: The Roncador Experience
Authors: Neto E. , Maurício J. , Waclawek I.
Published: October 2008

The exploration and production (E&P) segment of the petroleum industry has progressively been led to act deeper. In Brazil, where the deep water (400 to 1,000m WD) and ultra-deep water (1,000 to 2,000m WD) have been the segments responsible for the major portion of the overall country petroleum production (approx. 1.3 MMBPD), one can find in Campos Basin the main arena for the pioneer deployment of new technologies. CSO has been working in this environment as a strong partner of Petrobras, helping them to reach their main objectives, from engineering to product manufacturing and supply, installation and commissioning.

This paper will describe:

The technical solutions incorporated in the design of flexible lines of up to 9.2" in 1,500m WD and 6" in 2,000m WD, well in excess of any previous design.

The installation procedures developed and the up to date installation experience in the field, the challenges encountered and lessons learned.

It will also mention the strategies that are being adopted by Petrobras and CSO to overcome the main technological ultradeepwater challenges, to go beyond the 2,000m WD mark.

Introduction

Petrobras history in Campos Basin is discerned by a permanent challenge to overcome deeper water depths. The discovery of giant fields, like Marlim, Albacora and more recently, Roncador, in water depths ranging from 1,500m up to 2,000m, has demanded the development of new technologies, mainly the optimization of subsea hardware, installation and operational procedures.

Flexible pipes have played an important role in the history of oil production in Brazil, gradually building an outstanding reputation of reliability and cost-effectiveness.

No other oil province worldwide has applied flexible pipes so intensively as Campos Basin, where up to the present date there are about 2223km of risers and flowlines installed. For Petrobras, flexibles is the best way to make feasible production of oil fields in a short time, even before the reservoir delimitation and subsea layout consolidation, as they can be easily recovered, inspected, repaired, re-laid and connected in new sites.

Flexible pipes are composed of unbonded layers of plastic and steel, each layer being designed to resist to a specific loading, such as: crushing loads, internal pressure, collapse pressure, axial loads, torsion and so on and may be designed both for dynamic (risers) and for static (flowlines) applications.

The recent advances on the application of flexible pipes in deeper waters associated with a significant CSO R&D effort on the improvement of current structure design has shown that the adoption of flexible will continue to have a large demand in Campos Basin.

The main goal of this paper is to describe how Petrobras has dealt with the necessity of starting oil and gas production on Roncador ultra-deep waters in a short period of time, and what has been done by CSO and Petrobras to overcome the main challenges of this field.
Conversion of Tankers into FPSOs and FSOs: Practical Design Experiences
Authors: Neto Tomazo Garzia , Lima Heitor Augusto de Souza
Published: October 2008

The fleet of FPSOs and FSOs has been growing in the last years and is expected to grow more quickly in the coming years. The reason for fleet growth are the deep-water production, the increasing number of offshore fields that are being discovered and the need for fast-track development. The present fleet of FPSOs is composed by more than 65% of converted units and the fleet of FSOs is almost 100% of converted units. The conversion of an existing tanker into an FPSO or FSO is, in most cases, more economical and takes less time than a newbuilding. There are several factors that should be considered in a FPSO or FSO conversion to have a successful project. Based in the experience gained in the successful conversion of four FPSOs and FSOs for the deepwaters of Campos Basin - Brazil, several aspects that should be considered in the design for a conversion of a tanker into an FPSO or FSO are described. Critical issues like the selection of the vessel to be converted, project start up structural design installation of large capacity production processing facilities will be addressed.

Introduction

The fleet of FPSOs and FSOs has been growing in the past years and is expected to grow more quickly in the coming years. The reasons for the fleet growth are the deep-water production, the increasing number of offshore fields being discovered and the need for fast-track development. The main advantages of FPSO utilization includes:Integration of several functions in one vessel;Large deck area;Small variations of draft due to weight of production processing facilities;Flexibility in the vessel selection;Simple construction;Reduced investment cost;Short time schedule;Easy decommissioning after completed field production.

The conversion of an existing tanker into a FPSO is, in most cases, more economical and takes less time than a newbuilding FPSO.

Nevertheless a FPSO cannot be considered as a tanker with a different payload, that is the production processing facilities. The function of a FPSO is totally different from the function of a tanker in many aspects of design, conversion/construction and operation. The proper understanding of the function of FPSO is an essential element for the successful design and conversion/construction.

The FSO is less complex than an FPSO but, except for small vessels in shallow waters, cannot, also, be considered as a tanker. In deep waters and harsh environments the mooring and offloading systems and the need to stay on site for periods as long as 20 years are responsible for significant modifications in the vessel.

The intent of this paper is to discuss some aspects of FPSO and FSO conversion design for installation in deep waters and mainly related to the vessel.

The FPSO Fleet

The present FPSO fleet is composed of about 80 vessels, with about 66 vessels in operation and about 14 vessels in conversion or construction, and the FSO fleet is composed of about 80 vessels with about 77 vessels in operation and 3 vessels in conversion.
Nile - Design and Qualification of Reeled Pipe in Pipe for Deepwater
Authors: Tough Gordon , Denniel Sylvain , Al Sharif Majid , Hutchison John
Published: October 2008

The design requirements for the BP Nile pipe in pipe system required the employment of several high performance pipeline components. Of these components, the insulation system, buckle arrestors and water stops were being installed on a pipeline for the first time.

This paper presents the design sequence for these components and a summary of the qualification programme performed.

Introduction

The Nile field is located approximately 85 miles SE of New Orleans, Louisiana and is located in two blocks: Viosca Knoll (VK) 913 and 914. This field is expected to produce primarily gas condensate. The Nile field will be developed as a sub-sea tieback to the Marlin TLP, located in VK 915 at a water depth of 3245 feet (989 m). The Nile tieback comprises a 7.5 km long 6" × 10" pipe-in-pipe connected to a 6" steel catenary riser. The Overall Heat Transfer Coefficient (OHTC) requirement for the pipe in pipe is 0.21 BTU/°F.ft2.hr (1.2 W/m2K). The design temperature is specified as 95°C. This paper will outline the design process and summarise the qualification programme performed for insulation material, pipeline centralisers, buckle arrestors and reelable water stops.

Design: Insulation & Centralisers

An insulation requirement of an OHTC of 1.2 W/m2K is particularly challenging, however, when combined with a water depth of approximately 1000 m and the high design temperature, there is a limited selection of suitable insulation materials. The design parameters dictated that a pipe in pipe solution was required and it was on this basis that the project was specified.

Insulation Material Selection.

There are three pipe in pipe insulation materials which were considered for selection to meet these performance requirements; polyurethane foam (PUF), mineral wool and microporous insulation. Each material has specific advantages in terms of insulation performance, operating temperature range and relative cost. A comparison of the thermal conductivity of each material is presented in Figure 1.

In the course of previous CSO development work each of these materials had undergone both simulated installation and thermal evaluation to assess their suitability. Furthermore a detailed heat transfer model had been developed by CSO which allowed the required thickness of each insulation material to be determined. A first assessment of required thickness of the above materials is presented in Table 1. From a first review of the results it was clear that the thickness of mineral wool required is too great for a 10" carrier pipe and a 12" pipe would be required. To use a larger diameter carrier pipe would increase procurement cost, and significantly increase pipe lay top tension. This option was not considered further.

Two densities of PUF were considered in the design process. The higher density PUF (85 kg/m3) would require that almost the entire annulus was filled with insulation. This has an impact on the fabrication procedure.
Roncador Field Development with Subsea Completions
Authors: Juiniti Ricardo
Published: October 2008

The development of the offshore industry introduced subsea completions as a means to produce hydrocarbons under the water in an economic way. Since the first subsea completion in the beginning of the 60's, an increasing number of installations occurred around the world during the incoming decades and particularly offshore Brazil after 1979, when the first installation was made at 189 meters of water. Different needs led Petrobras to use subsea completions in increasing water depths what called for different projects which surpassed important milestones, like the installation in water depths deeper than the diving limit and over 1,000 meters. Nowadays the deepest installations of subsea trees in the world are being performed in Roncador field where up to date 5 subsea trees, including the well 7 RO 8 RJS at 1,877 meters, were made in the range of 1,850 meters of water. The technical solutions developed in house for subsea completions in ultra deep water showed to be reliable and became a standard operation. Moreover, improvements in the overall time spent for these completions were also made.

As other subsea trees will be installed in Roncador field, the analysis of the efficiency of the installations performed so far will improve future results.

This paper will show the evolution of the subsea completions offshore Brazil in order to explain the solutions used in ultra deep waters field and then show a comparison of the time spent in different subsea completions in Roncador field. It will also anticipate proposed solutions for even deeper waters.

As ultra deep water exploration is surpassing the 2,000 meters barrier, reliable and efficient subsea completions hardware and techniques are a must in order to economically develop future discoveries.

A Brief History of Subsea Completions

Subsea completions were introduced in the beginning of the 60's in the Gulf of Mexico as a means to produce hydrocarbons under the water in locations far from the existing platforms and as a test for production in deeper waters, since at that time offshore production was only achieved with the use of fixed platforms. Soon later subsea completions were also introduced offshore California to produce gas directly to shore.

During the 60's all subsea trees installations were done in the USA, and the Through Flowline Concept (TFL) was widely used as it allowed tools like a pressure gauge, to be pumped downhole and recovered after the job was accomplished. Other features of these subsea trees were the diverassisted flowlines pull in and direct hydraulic operated subsea valves.

By the end of the 60's, the number of installed subsea trees was 68, at a maximum water depth (WD) of 130 meters, all of them in the USA.

With the discovery of hydrocarbons in the North Sea, subsea trees were also used as a means to accelerate production, to acquire more reservoirs information as well as to get an earlier cash flow.