bluuebunny/crossref_metadata_2025_split huggingface dataset:
In-Situ Post-Weld Heat Treatment of Wet Welds
Authors: Szelagowski Peter , Ibarra Santiago , Ohliger Annegret , dos Santos J-F. 
Published: October 2008

1.0 Introduction
There is a substantial interest in implementing wet welding for structural repairs of offshore installations. Some of the restrictions to its use are heat affected zone (HAZ) hardening and cracking, and the inability to produce wet welds that meet the bend test requirements of a surface weld. Restrictions to the application of wet welding are even more sever in the North Sea where high strength, high carbon equivalent structural steels are used. A reduction of the diffusible H2 contents of wet welded joints (i.e. lower risk of H2 induced cracking) would certainly lead to a re-evaluation of the process regarding its practical application, especially considering high carbon equivalent steels. This is more so in face of the acceptable mechanical properties and low defect rates achievable with some of the electrodes presently available.
Such desirable reduction in the weldments H2 content could be achieved through an "in-situ" (underwater) post weld heat treatment (PWHI). In order to evaluate the feasilibllity of such heat treatment method a series of tests has been carried out in which bead-on-plate welds have been deposited on high carbon equivalent base plates and then submitted to different "in-situ" heat treatment procedures. This report presents the results of these preliminary investigations.

2.0 Theoretical Background
Due to the fast cooling rates and the high hydrogen content, characteristic of weldments produced in wet environment, hardening and cold cracking in the HAZ and weld metal are possible, especially in the case of high carbon equivalent steels (CE &gt; 0,40 %) /1/.
Postweld heating methods have been investigated in order to improve the mechanical properties of underwater welds 12,31. One way to prevent cold cracking in underwater welds is to facilitate the diffusion of atomic hydrogen by heat treating immediately after welding. Suga /2,3/ investigated the effect of post-weld heat treatment on the occurrence of cracks and on the evolution process of hydrogen out of the welds using beadon-plate runs (13Omm in length) deposited underwater. After removing the slag, the test plates were immersed into an isothermal bath within 60s after completion of the welding. The test plates were kept in the bath for J)l'eset times, then cooled in water and left in air at room temperature. Suga /2,3/ obselVed the occurrence of under bead cracks in the HAZ of underwater welds within a period of about 5 min. after welding. His observations stated that under bead cracks as well as root cracks could be prevented by "in situ" PWHr above temperatures of 100 DC with appropriate holding times.
Similar results have been achieved by Ibarra et. al. /4/ using the multiple temper bead technique. This technique involves immediately placing a second pass over the previous one to soften the hardened HAZ and eliminate hydrogen. The experimental and practical results obtained indicated that this method was successful in assisting hydrogen diffusion out of the weldment /5/.
Clad Steel: An Engineering Option
Authors: Smith L.M. 
Published: October 2008

ABSTRACT
Corrosion resistant alloy clad steel has been available in various forms for over 40 years and is being used increasingly in the oil and gas production industries. In the context of the specific requirements of this industrial sector, methods of manufacturing clad plate, pipe and fittings are given along with welding details and information on existing field applications of clad products.

1. INTRODUCTION
The use of corrosion resistant alloys (CRAs) for the control of corrosion in oil and gas systems has a number of benefits. Production systems constructed of correctly selected CRAs (based on appropriate laboratory testing or previous field experience in similar enVironments) will provide a safe, leak-free system for the full duration of a project. Whilst the inital capital expenditure often appears to be higher for a CRA system there are great savings to be made in reduced processing requirements through the safe handling of wet corrosive fluids. If well fluids can be transported to shore or to an existing platform without drying then the cost savings in equipment, weight andspace can be more than sufficient to cover the expense involved in the CRAs needed to handle the fluid from the well to the processing facility.
Additional savings can be made in operating costs since corrosion inhibitor injection is not required and inspection and maintenance costs are greatly reduced compared to a carbon steel production system (with or without internal organic linings). Thus if a life-time costing approach is taken CRAs can often be show to be an economic corrosion control option for oil and gas production systems.
Nevertheless, CRAs contain expensive alloying elements, particularly the more highly alloyed materials required for corrosive sour production systems. Clad steel is a composite product developed to provide effective and economic utilisation of expensive materials. The cladding layer which will be in contact with the corrosive fluids is made of the corrosion resistant alloy whilst the less expensive backing steel providesthe strength and toughness required to maintain the mechanical integrity. Because high strength backing steel can be utilised, wall thicknesses can be reduced relative to solid CRAs thus reducing fabrication time and costs.
The cost saving from using clad steel rather than solid CRA is particularly valid when the total thickness increases or when the cladding grade becomes more complex and hence expensive. An indication of the sort of savings which can be made is illustrated for integrally bonded clad plates in Figure 1. Clad steel plates have been utilised with great success in processing vessels, heat exchangers, tanks and a variety of material handling and storage facilities as well as for making longitudinally welded clad pipe. Clad steel has been available in various forms for more than 40 years and has been widely used in the chemical, oil refining and chemical transport industries and more recently in oil and gas production. Yet despite this there are still concerns regarding the use of clad steel..
First Emergency Shutdown Valve, Norwegian Sector
Authors: Eriksen Gunnar , Bondevik J.O. , Bergum Bernt 
Published: October 2008

ABSTRACT
The Subsea Emergency Shut Down Valve (SESDV) was Installed in December 1991 as an Integrated part of the Oseberg Multiphase Transfer System (MTS), between the Oseberg Field Centre and the Oseberg C platform. This paper describes the concept evaluation, design philosophy, fabrication, testing and installation of the SESDV.
Due to the discovery of additional oil reserves which could be reached from the Oseberg C platform a phased development of the reserves was decided, As a consequence, a new safety evaluation of the C platform had to be performed. This concluded that in order to minimise consequential damages to people and platform in case of a fire at sea or a riser rupture situation, a SESDV should be Installed close to the platform.

INTRODUCTION
The Oseberg Field, is located in blocks 30/6 and 30/9 in the Norwegian Sector of the North Sea, was decided to be developed by Norsk Hydro and it's five partners. The first stage of the Oseberg Field Development was completed in December 1988, when the Oseberg Field Centre was put in operation. The second stage of the Oseberg Development was completed in September 1991, when the Oseberg C platform was put in operation after an offshore hook-up period of four and a half months. A multiphase pipeline (MTS) has been installed and is due to be on stream by March 1992. The lay-out of the Oseberg Field is shown in Fig. 1.
The MTS pipeline will transport unprocessed oil from the C platform over a distance of 15 km before being processed on the Oseberg Field Centre. Due to the corrosiveness of the fluid the design life time of the pipeline is 10 years.
With the conclusion of the platform-safety report in mind, two conceptual studies of SESDV was run in parallel, in summer 1990 in order to combine existing knowledge from Norwegian Sector with practical knowledge from the English Sector. With the results of the two studies, specifications were made. An EPC contract was awarded in February 1991 for delivery of the complete SESDV system by October 1991.
* The partners of Norsk Hydro Produksjon NS in the Oseberg development are: Den norske stats oljeselskap (STATOIL), Saga Petroleum NS, Elf Aquitaine Norge NS, Mobil Exploration Norway inc., Total Marine Norge NS.

PLATFORM SAFETY - SESDV LOCATION
In case of a riser rupture, the riser for the MTS with the valve at the seabed will be emptied at a much shorter time than used for closing the valve. Therefore it is the valve closure time more than the location that determines the amount of gas released, provided it is not located too far away from the platform along the pipeline. With the SESDVlocated 500m from the platform, the blowdown time is about 25 seconds (assuming immediate closure of the valve), or approximately the acceptable maximum valve closure time.
Lifeboat Launch Simulation and Its Application to Safety Assessment
Authors: Luo Yong , Trickey J.C. , James C.E. , Jack R.L. 
Published: October 2008

ABSTRACT:
The paper deals with the motion simulation of lifeboats launched from fixed or floating platforms and its application to collision risk assessment. The mathematical model of the Davit launch system is presented. By solving the motion differential equations, the three dimensional motion responses of the lifeboat and the platform are simulated in the time domain and the clearance between the lifeboat and platform structural members are monitored. Numerical examples are given and key parametric effects are investigated through deterministic and probabilistic analyses. It is demonstrated that the motion simulation combined with probabilistic analysis techniques can provide an effective tool for quantitative risk assessment of offshore emergency evacuations using lifeboats.

1. INTRODUCTION
During an emergency evacuation from offshore fixed or floating platforms, it is of vital importance that lifeboats can be successfully launched and disconnected from the platform. This is actually one of the recommendations made in Cullen's Report [1] into the Piper Alpha disaster which states: "Operators should be required by regulation to submit to the regulatory body for its acceptance an evacuation, escape and rescue analysis in respect of each of its installations".
Aimed at improving the understanding of thebehaviour of lifeboats during launch and assessing the risk involved due to possible collisions with platform structural members, the lifeboat launch operation is studied using response simulation techniques. The current study focuses on the traditional Davit launch of lifeboat system for TEMPSC (Totally Enclosed Motor Propelled Survival Craft) whereby the lifeboats are lowered vertically from winches on two cables (see Fig.1). It addressee the following main issues:Motion responses of lifeboats during descending from floating or fixed platformsLifeboat movements during turning and sailawayKey parameters and their effects on motionand risk of collisionProbabilistic analysis as a tool for safetyassessment
For lifeboats launched from floating structures Such as semisubmersible units, the lifeboat motion response caused by environmental loading and the platform motion is mathematically modelled. The motion equations are solved numerically to simulate the lifeboat and platform responses and monitor the occurrence of collision in the time domain. Impact velocity can be computed if collision occurs to determine the extent of damage.
Investigations of key parametric effects are carried out. The main parameters studied are the types of platforms, severity of environment, vertical descent speed, disconnection time and lifeboat heading. Useful results are obtained which will help the development of appropriate evacuation procedures.
It is also demonstrated in the paper thatprobabilistic techniques can be incorporated into the analysis to obtain a quantitative indicator of the risk level of lifeboat launch. The results canbe valuable for aseessing the adequacy of evacuation procedures using lifeboats.
Requalification of a Platform in Cook Inlet, Alaska
Authors: Bea R.G. , Landeis B.T. , Craig M.J.K. 
Published: October 2008

ABSTRACT
This paper outlines and illustrates an engineering evaluation procedure for re-qualification of high consequence offshore platforms. The procedure is illustrated with application to a Cook Inlet patform that was damaged by a blowout. The anaPyses and evaluations documented in this paper indicate that the damage was successfully repaired, and that the structure in its repaired condition is fit for purpose.

INTRODUCTION
In 1985, a platform operated by Unocal (coowned by Marathon and Arco) located in Cook InIet, Alaska (Fig. 1), experienced a blowout which created a large crater encompassing three of its four legs (Fig 2.) The blowout serious y damaged the foundation (crater depth at Leg-1 was approximately 80-fi deep) and caused some damage to the superstructure.
The foundation was repaired by filling the crater with 100,000 cubic yards of gravel and by driving twelve 20-in diameter insert pies into the existing piles in Leg-1. Preliminary studies of the performance of the repaired platform when it was subjectedto lateral loadings from earthquakes and ice floes indicated that a more rigorous and detailedevaluation of the serviceability of the platform during extreme conditions was necessary [1,2].

BACKGROUND
The platform location is in upper Cook Inlet in a water depth (mean lower low water) of 125 ft. The maximum tidal range is approximately 30 ft.
The Inlet is covered with ice during the wintermonths. Strong tidal currents move ice up and down the Inlet twice a day. Ice thickness can range from 3 fi to in excess of 6 ft (rafted, Stamuki).
Cook Inlet is situated in one of the most active seismic zones in the world. Numerous majorearth shakes have occurred in this area including the 1964 Good Friday Prince William Sound earthquake (magnitude 8.5). In the last 65 years, 15 events of magnitudes greater than 6 have occurred in thisarea.
Subsurface soil conditions vary greatly and ran e from soft unconsolidated clays on the west sideoft i?e Inlet to boulder-covered extremely stiff clays in the middle and east side. In the upper Inlet the soil conditions generally can be classified as deep, firm alluvium.
The platform is a steel, tower-type platform that has four 17-ft diameter legs (Fig. 1). The toweris braced with horizontal and vertical X-bracing below water (Fig. 1? 3). The le s span the tidal zone (kept open to minimize ice loafing) and are joined at the deck level by 17-ft diameter horizontal beamtanks. The multi-level enclosed drilling and productiondecks are mounted on top of the beam tanks.
Each of the platform?s legs contain 12, 33-inand 26-in diameter two stage piles (Fig. 3). Inside the piles are well conductors (multiples strings of casing) that are cemented to the formation and the piles.
The soil conditions at the platform (Leg-1 profile, Fig. 4) consist of very strong stiff clays belowpenetrations of about 125 ft overlain b lower strength stiff clays and the gravel used to F111the blowout crater.
Design and Installation of the North Dauphin Island Platform
Authors: Beal D.D. , Allen J.D. , Datta B.N. 
Published: October 2008

ABSTRACT
The shallow water of Mississippi Sound restricted the selection of structural concept to support a 70 mmscfd gas processing facility. The project team picked a structure type which could be floated over and set on pre-installed piling instead of the traditional lifted deck. This mode of installation provided for a competitively bid and economical installation since it used equipment which is commonly available at reasonable day rates.
Installation procedures for the 1400 ton deck insured a gradual controlled transfer of load from barge to piling. Shock cells in the legs, compressible supports on the barge, sand cans in the legs and on the barge, and a digital read-out of loads from strain gages on the legs allowed gradual transfer of deck load from barge to pile. Testing of the shock cells and a sand can before actual use insured proper operation offshore.

INTRODUCTION
The North Dauphin Island field consists of about nine square miles in Mississippi Sound just north of Dauphin Island, a barrier island off the coast of Alabama. Six satellite wells produce gas from the Shallow Miocene formation to a central gathering facility, the North Dauphin Island platform, in Alabama state tract 73. The platform houses sweet gas processing equipment including two 2200 H.P. reciprocating compressors. No production wells are located on the platform.
The environment of Mississippi Sound made the design and installation of the North Dauphin Island platform unique in comparison with the vast majority of Gulf of Mexico facilities. The platform site, shown in Fig. 1, is 2400 feet south of the Intracoastal waterway and a half mile north of Dauphin Island. The water at the site is only 11 feet deep and water depths in the field are a maximum of about 13 feet. Only one heavy lift barge was available in the Gulf of Mexico which could lift a 1400 ton deck in the shallow water, and designing the structure to be totally dependent on this barge couldhave burdened the project with some significant constraints.
The regulatory environment also made this project unique. At the time of design, the state of Alabama required that oil and gas operators discharge nothing into state waters during construction and operation offacilities.

CONCEPTUAL DESIGN
The unique site conditions offered designers several structural alternatives from which to choose. While there was a single heavy lift barge capable of working theshallow water, the owner decided to avoid the complications which would accompany dependency on a single piece of equipment. Other viable alternatives were established and compared in a brief technical and economic evaluation. Environmental and aesthetic aspects of the alternatives were also examined. The structural alternatives which were considered are listed below. In all alternatives the deck would be outfitted with process equipment prior to offshore installation.
Installation of the South Pass 52 Platform
Authors: Allen J.D. , Beal D.O. , Kessler K.J. , Mukerji Paddy 
Published: October 2008

ABSTRACT
Installation of the drilling and gas production platform for South Pass 52 required extensive planning and careful consideration of risks brought about by the tripod configuration, economic limitations on exploiting a marginal prospect, soft soils, and potentially significant currents. The jacket, 548 feet long and 2700 tons, relatively light for the water depth, was lifted from the barge at sea. Five foot deep skirts on the mud mats helped mobilize adequate bearing capacity and minimized mat size. Carefully selected ballasting, attention to currents and weather forecasts, and a short exposure time partially compensated for the limited resistance to overturning of the jacket before piles were driven. The jacket made the first use of a new type of pile gripper, shop tested before deployment, which could be used to grip stabbed or partially driven piles for levelling the jacket and minimizing jacket motion during grout set-up. Performance of the plans and systems for installation was generally satisfactory. The risks accepted for the installation were believed to be near the economic optimum. The platform is currently the tallest offshore tripod platform in the world.

INTRODUCTION
The South Pass 52 platform is a six-slot, pile-supported steel platform in 531 feet of water which supports a drilling rig and production facilities for 60 mmscfd of gas. The combination of relatively low gas production rate and deep water made this prospect a marginal one requiring an economical structure. The general configuration of the jacket and deck is shown in Fig. 1. The jacket is supported by three 72" diameter skirt piles penetrating to depths of 430 to 470 feet below the seafloor. The deck consists of a main deck and a production module. The minimization of weights and areas was accomplished in the deck and module by designing to tightly accommodate a particular drilling rig, by not providing any quarters except those with the rig, by using the space vacated by the drilling rig for compression after the wells are completed, and by using a three-level module for most of the production facilities. The tripod design minimized weight in the jacket. Gas is sold directly to a nearby pipeline and natural gas liquids are piped to ARCO's Mississippi Canyon 148 platform. More details on the design of the platform were given by Whicher et al (1991.)
The contract for fabrication and installation of the South Pass 52 jacket and deck was awarded in July 1990. Rolling of tubular members began soon thereafter in a fabrication yard on Bayou Boeuf in Morgan City, Louisiana. The jacket was fabricated in the Harbor Island yard near Aransas Pass, Texas. The deck and production module were fabricated and outfitted at two different yards in New Iberia, Louisiana. The jacket was installed in September 1991 and facilities were started up in early 1992. This paper describes the work done to prepare for and complete the load-out, transportation and installation of the platform.