bluuebunny/crossref_metadata_2025_split huggingface dataset:
Load Monitoring at the Touchdown Point of the First Steel Catenary Riser Installed in a Deepwater Moored Semisubmersible Platform
Authors: Edwards Roderick Y. , Machado Remo Zauli , Hennessy William F. , Campman Craig R. , Bailon Hector 
Published: October 2008

Abstract
A 10-inch Steel Catenary Riser (SCR) was installed in the Petrobras XVIII semi-submersible production platform, moored in 910 meters water depth in the Marlim field, Campos Basin, offshore Brasil. This is the first SCR ever installed on a floating moored platform.
In order to evaluate and verify the methodologies and to calibrate the numerical models used in the riser, mooring system, and platform design, it was necessary to establish a monitoring program for all the relevant parameters (environmental, platform positions and motions, riser loads and stresses at the top and at the touch down point (TDP), and vortex induced vibrations).
The TDP monitoring system consists of several strain-gage collars in pipe sections close to the TDP, subsea strain conditioning, control and data storage electronics, and an acoustic telemetry data transmission system. Mobilising this complex system required several innovative solutions.
The paper describes the monitoring system developed to measure tension and moments at the Touch Down Point (TDP) region of an SCR, its installation and operational aspects, and its performance to this date.

Introduction
As part of its continuing effort to develop hydrocarbons in deep water responsibly and cost effectively, Petrobras initiated a project to assess the feasibility of using Steel Catenary Risers (SCR) on moored, floating production platforms in deep water. Numerical analyses to predict the stress history in the touch down region of the SCR sometimes presented different results depending on the numerical model used. Accordingly, Petrobras considered it essential to obtain full-scale data from a prototypical 10 inch SCR installed in the PXVIII, a semisubmersible FPSO moored in 910 meters of water. The experiment was outlined by the Petrobras R&D Center's Exploitation Projects Division. Its Subsea Engineering Group prepared Technical Specifications for the Environmental, Platform Positions and Motions, Top Loads, TDP Loads and Vortex Induced Vibrations Monitoring Systems and its processing, and is conducting this monitoring project. The measurement of the stresses in the touch down point of an SCR in deep water had never been done before and presented several difficulties. This paper describes the development of a monitoring system to do that.
Performance Record for FPSOs and Shuttle Tankers
Authors: Wallace Kimberly M. , Zaner Stacy A. 
Published: October 2008

Abstract
Industry interest in tanker-based floating production systems in the Gulf of Mexico (GOM) has brought forth the need to evaluate the worldwide performance of these systems regarding oil spill safety. This paper discusses the incidence of oil spills from Floating Production, Storage and Offloading (FPSO) systems and shuttle tanker operations throughout history, based on public data and a recent industry survey. Oil spill statistics are presented considering the following factors:Geographical locationVessel type and sizePrimary operation in progress at the time of the incidentCause of SpillSpill volume
Results indicate that oil spills from FPSOs and shuttle tankers are very rare, and the industry can continue its aggressive pursuit for utilization of an FPSO in the Gulf of Mexico.

Introduction
During the past 22 years, tanker-based floating production systems (FPSOs) have been utilized in a wide variety of water depths, weather conditions and field types. These systems are among the most flexible options for developing offshore oil fields. Generally, a newbuild FPSO is designed for a field life of 20-25 years and a tanker converted for FPSO service is designed for a field life of 10-15 years. However, Walter Winkworth, Manager of Offshore Services for Lloyd's Register of Shipping, states in an OCS report that FPSOs can be designed for a field life of up to 50 years (for a shallowwater, nearshore FPSO)1. FPSOs can also be used on a shortterm basis for an Extended Well Test (EWT), an Early Production System (EPS), or can be relocated for use on multiple fields. They can be designed to operate in water depths as shallow as 50 feet to extreme deepwater, and a wide range of weather conditions.
FPSOs are suitable for several scenarios that are applicable to the GOM, as listed below:In a marginal field, an FPSO can provide full-scale production operations without the expense of a purpose built fixed facility. The FPSO can then be re-used elsewhere, thereby saving money for the field owner.EWT or EPS operations require a temporary installation such as an FPSO.Ultra deepwater fields can be developed with the use of an FPSO. With an FPSO, a massive structure is not required in order to develop the field, as is the case with a Tension Leg Platform (TLP) or other fixed structure, since an FPSO is not sensitive to topsides weights or space restrictions. Note: Reserves totaling more than 4 billion barrels of oil have been located in water depths ranging from 1600 feet to 5900 feet (500m to 1800m) in the Gulf of Mexico in just the last six years.2An FPSO can be designed to stay on location during a hurricane or be able to eave the operating site during thes torm.Remote field locations, far from existing platforms or pipelines, can be developed with an FPSO since it provides its own storage and offloads to shuttle tankers. This eliminates the necessity of an oil sales pipeline.
Overview of Britannia Subsea Corrosion-Control Philosophy
Authors: Kolts J. , Joosten M. , Salama M. , Danielson T.J. , Humble P. , Belmear C. , Clapham J. , Tan S. , Keilty D. 
Published: October 2008

Abstract
The overall corrosion control and sand production management philosophy for the Britannia subsea development is outlined. The philosophy includes the materials selection for wells, manifolds, and flowlines, corrosion control by inhibition, and sand erosion prediction and monitoring. Comprehensive corrosion and erosion monitoring systems have been installed to assure the integrity of the subsea system. Finally, the corrosion control philosophy was developed and integrated into the operating philosophy and practice.

Introduction
Britannia is a corrosive gas-condensate field in the North Sea. The general concept for corrosion control in the subsea system was to use corrosion resistant materials in the wells, jumpers, and manifold, and carbon steels with corrosion inhibition in the subsea flowlines. In addition to the corrosivity of Britannia, the system was designed to control erosion. To ensure the integrity of the production and process systems, erosion at high flowrates, sand settling, and inhibitor effectiveness under sand beds were addressed.
The Britannia conditions subsea will be to temperatures of 115°C and CO2 partial pressures in flowlines to about 6 bar (85 psi). For pure water, this relates to a pH of 3.9. The velocity in the subsea flowline may be up to 18 m/s (60 ft/s). This could be higher if the platform arrival pressure is lowered. Recent production rates are 350 MMSCFD. The high temperatures and flow rates were considered in the design against corrosion and erosion.
The production contains about 100 bbl of hydrocarbon condensate and 2-3 bbl of water per mmscf. Table I displays the calculated condensate volumes used for flow modeling. The actual production on Britannia confirms these values.
The primary areas of focus in the design were corrosion inhibition of the subsea flowlines, corrosion/erosion resistance of the manifold and flowlines, selective weld corrosion resistance of the flowlines, and sulfide cracking resistance of the downhole tubulars. Each will be discussed.
TABLE I TOTAL LIQUID IN EQUILIBRIUM WITH 1 MMSCF BRITANNIA GAS, HYDROCARBON (WATER), BBL (Available in full paper)

METALLURGY OF DOWNHOLE EQUIPMENT
Typical conditions for these gas condensate wells would include up to 15 ppm hydrogen sulfide, 2.6 mole % carbon dioxide and 50,000 ppm chlorides. Therefore, type 13% Cr alloys were chosen to provide adequate corrosion resistance. Depending upon tubing design requirements, both API 5CT Grade L-80 13% Cr and proprietary modified 13% Cr with a 110 ksi SMYS were selected.
Friction Welding - Technology for the New Millennium
Authors: Blakemore Gordon R. 
Published: October 2008

Abstract
This paper describes the process of friction stud welding and how it has been developed for use in the North Sea. Attention is given to explaining why friction welding does not suffer the inherent problems associated with conventional welding techniques, (particularly when used underwater), how superior metallurgical integrity can be achieved, and how (unlike any other welding method) the process can be used at ANY water depth without any change to weld parameters or weld quality.
Following this, the paper describes the hyperbaric trials and then the work carried out in executing the deepest LIVE friction welding operation in the world to date. The work was carried out in 395 metres of water West of Shetland and involved the friction welding of anode continuity tails to riser base piles using a work-class ROV (Remotely Operated Vehicle).
The paper documents the work currently being carried out by a Consortium of European Companies funded by a European Community grant for the development of a friction welding system using a process known as Friction Stitch Welding and the associated deployment equipment to carry out crack repairs on vessels, platform structures, and pipelines.
Finally the paper outlines the proposed development to be carried out in extending the crack repair technology to enable the joining of pipe up to 42 inches outside diameter at extreme water depths.
In summary, with the constant search for resources in ever deeper water this technology will provide the Engineer with a reliable and cost effective method of joining materials at extreme depths for construction, repair, maintenance, salvage, corrosion protection and many other tasks. - TECHNOLOGY FOR THE NEW MILLENNIUM.

Introduction
The process of friction welding has been available forworkshop use on a commercial basis since the 1950's.
It is used extensively in the automotive and aerospace industries because of its reliability, repeatability, weld integrity and ease of automation.
In 1983 the world's first "portable" equipment was built for use in the North sea and was used to great effect for making anode attachments at 150 metres water depth. This was documented and presented at previous OTC.1
Since then equipment has become truly portable, and the development of computer technology has provided the facility of much smaller and more accurate control/monitoring systems with in-process proof testing.2
Thus the equipment has now attained an extensive track-record for use both topside and underwater for repair, maintenance, construction and many other applications in the offshore, marine, defence, construction and nuclear industries.
Developments in Proposed ISO Guidelines for Design of Offshore Platforms to Resist Earthquakes
Authors: Bea R.G. , Craig M.J.K. , Gudmestad O.T. , Karthieghian V. , Pradayana G. 
Published: October 2008

Abstract
This paper summarizes current developments in the International Standards Organization (ISO) proposed guidelines for design of offshore platforms to resist earthquakes. These developments include updated evaluations of seismic exposures in the U.K. and Norwegian Sectors of the North Sea, offshore Japan and Indonesia, and in the Bay of Campeche Mexico. Guidelines have been developed to permit design analyses based on either 100-year or 200 year bases. Recent results from measurements and analyses of the effects of local soil and geologic conditions are used to update the proposed ISO guidelines. Updated developments also address steel and concrete elements in offshore platforms. Both 'fixed' and 'information sensitive' load and resistance factors for steel and concrete elements have been developed to increase the ease of use of these guidelines. The updated guidelines in this paper provide important improvements in development off reliability based criteria for design and requalification of fixed offshore platforms. These improvements are in characterizations of seismic exposure, effects of local soil and geologic conditions on ground motions, performance characteristics of steel and concrete elements and pile and mat foundations subjected to earthquake loading effects, and in characterization of dynamic loading effects in fixed offshore platforms subjected to ultimate limit state earthquakes.

Introduction
A first-generation LRFD ISO guideline for design of steel, pile supported, template-type platforms to resist earthquake induced loading has been developed.1 This guideline was based on the API RP 2A LRFD guideline and on the collective experience and judgment of the ISO TCG7-WG3-P5 committee members. During the first generation developments, limited verification studies of the entire process were performed, there was limited documentation of the background for some of the key developments, and there were additional topics that needed to be addressed. Three general topics are addressed in this paper:seismic exposure characteristics,design response spectra characteristics,concrete gravity base structure characteristics.
Atlantic Crossing Film
Authors: Moore N.A. 
Published: October 2008

This film is a 30-minute, illustrated, seismic profile cross...section of the deep ocean floor and sub-bottom sedimentary layering from the island of Trinidad, B.W.I. to the port of Monrovia, Liberia. The survey program was initiated in June, 1967. The traverse to Liberia was completed in 14 days at an average vessel speed of 10 knots. The seismic profiling system was Teledyne Exploration's 120,000 Joule SSP System. Seismic data was recorded on a facsimile recorder, the detector streamer cable was Teledyne's 100 sensor, single-channel Hydrostreamer. The actual traverse length was about 3,500 miles.. Our film will show perhaps two thirds of the actual field sections. The data has not been processed in any manner.
The data shown consist of essentially continuous seismic profile records, with the vertical scale of the record a 4-second [from top to bottom] time scale, and a horizontal distance scale [across the screen] of approximately 15 miles. This produces a vertical-horizontal scale ratio of approximately 1:8. While this ratio could be altered by changing either the firing interval of the underwater seismic source or the vessel speed, the parameters selected were considered optimum for this traverse. Thus, we will see an unfolding of the .subsea bottom geology with the water surface at the top of the record. The first major event is the sea floor, followed by numerous reflector events which detail the sedimentary layering below the sea floor. One may estimate the depth of the sea floor by remembering that each second [one fourth of the vertical record length] from the top of the record down toward the sea floor, covers a distance of 800 fathoms; i.e., if the sea floor is seen at about 2 seconds, the water depth is approximately 1,600 fathoms.
Throughout the film, inserts have been added illustrating the equipment and the manner and methods of usage aboard ship. Geological interpretation is based on data in current publications. Positioning was by dead reckoning and celestial navigation except at the origination and termination of the seismic profile. As mentioned earlier, portions of the profile were edited out because of monotonous geology, and the need to limit the film to 30 minutes. One breakdown occurred near the halfway point of the traverse [mid-Atlantic rise] and about 300 miles of data were lost. The vessel used on the program was a typical work boat, 136 ft long and 26 ft wide [M/V Stranger]. The first film cut shows a similar survey vessel rigged with the same seismic profiler system. The vessel is shown leaving Port Arthur through the Sabine Channel. Illustrations of the deck rigging detail the 20-ft outrigger booms, from which the arcer electrodes are towed. This scene shows a wire dispenser for the Teledyne wire explorer [WASSP] attachments. Each boom is lowered into position and two electrical cables are released into the water. The cables are approximately 18 ft apart and extend about 150 ft astern of the vessel. The Teledyne crew is shown lowering one of the cables over the side. Cable pullers are used to simplify retrieving the cables while underway.
Chemical Overlays for Seafloor Sediments
Authors: Roe Thorndyke , Williams John S. , Migliore Herman J. 
Published: October 2008

ABSTRACT
Various materials and methods have been investigated to control the turbidity caused by the disturbance of seafloor sediments. The method selected as the most promising consists of the formation of plastic film over the sediments by casting from a compatible solvent system.
A formulation has been developed, and equipment to dispense it has been designed, fabricated, and is being evaluated.

INTRODUCTION
Poor visibility is one of many problems which man encounters when he carries out undersea operations. It has been reported that under ideal conditions, and at shallow depths, divers have been able to see clearly for 200 feet in all directions1 but generally the limit of visibility off the Southern California coast is fifty feet. This limit is drastically reduced if seafloor sediments are disturbed so that an undersea "dust cloud" is created. Material of this type can remain suspended for hours with the result that work must be greatly curtailed or suspended. In salvage operations, any prolonged delay could result in partial or complete failure of the mission. As man begins to place permanent structures on the sea floor, sediment stabilization is a problem which will have to be solved during construction and operation of these installations.

CHEMICAL METHODS
Three methods were considered as approaches toward solving the sediment stabilizing problem:use of flocculating agents,stabilization of the soil mass,formation of an overlay to cover the sediment.
Flocculating agents are effective in increasing the settling rate of suspended material. However, if the settled material is disturbed, an additional waiting period is required for it to settle again. Stabilization of the soil mass would require that rather large quantities of binding materials be injected into the sediment with a minimum of disturbance. This technique should be considered only when a permanent or semi-permanent foundation is required.
Formation of an overlay to cover the sediment was selected as the best of the three methods to solve the present problem.
Three methods were considered as possible solutions to the production of an overlay:the formation of a polymer gel by chemical reaction at the site,the formation of a gel by increasing the viscosity of a liquid because of low ambient temperature at the site,the formation of a plastic film at the site by casting from a compatible solvent system.
Roe and Williams2 and Epstein and Widman3 have reported on one or more of these methods, and the information can be summarized as follows:Formation of a polymer gel. Acrylamide can be polymerized in a soil formation4 and a proprietary product is sold for this purpose. Oceanographers have used this chemical grout in high concentrations in taking seafloor core samples.5 Polyacrylamide forms a tough gel under water, but the monomer is slightly neurotoxic and would not be suitable for diver use.
Hybrid Riser for Deepwater Offshore Africa
Authors: des Déserts Loïc 
Published: October 2008

Abstract
As hydrocarbon production is now contemplated for larger and larger water depths, the technical issues related to the import of the fluid stream onboard the floating production facility have to be well resolved. The hybrid riser concept, as developed today, brings a technically and commercially viable solution to this problem. The purpose of the present paper is to describe the latest developments achieved on the hybrid riser technology. The concept presented here is different than that developed for the Girassol field located offshore Angola as it incorporates improvements which have been made after the detailed design of the Girassol unit was completed. The paper gives details on overall geometry and governing criteria for the sizing of the system. Overall fabrication and installation procedures are also presented as well as the main results of the dynamic behaviour of the system when installed on its final location.

Introduction
When developing hydrocarbons in deep waters or ultra deep waters, that is to say from 1000 m to 3000 m, one of the biggest technological challenges that has to be overcome by the developers comes from the riser system. Indeed, raising the production stream from the sea bottom to the surface is the only feature, together with the mooring system, if not using a dynamic positioning system, which really depends on the actual water depth. The size of the floating unit supporting the production equipment does not vary with the water depth but mainly with the production throughput level and the amount of required storage. Likewise, the sub-sea equipment suitable for 1000 m is very similar to that suitable for 2500 m or even 3000 m, and the water temperature is the same at all these depths. At these depths the water temperature is closed to 4° C. This is rather cold when compared to the hydrate formation temperature, generally around 20° C, or to the wax appearance temperature that could be close to 30 or 40° C. When considering also that most of the reservoirs located in deep waters offshore the West coast of Africa lie in relatively shallow soil depth and are therefore relatively cold, the importance of the thermal properties of the riser system becomes quite obvious. This is why the riser system described in the present paper has been developed for particular applications in deep waters located offshore the coasts of West Africa.

Description Of The Tower
The tower described here-below has been designed for an application located in the Gulf of Guinea and in 1500 m of water. It is designed to allow the production of 150,000 bpd from 24 wells to be brough to the surface. This layout involves 12 flowlines arranged in 6 piggable loops, plus 2 water injection lines and 1 gas injection line. All these lines are gathered in 2 towers, each one incorporating 6 producing lines, 1 water injection line and 1 gas injection line.