bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use Of Corrosion-Resistant Weld Overlays For High-Pressure Applications
Authors: Maligas M.N. , Vicic J.C. 
Published: October 2008

ABSTRACT
High performance, corrosion resistant alloys CRA'S are specified for oilfield applications where severe environments such as general corrosion, pitting, crevice corrosion, chloride stress corrosion cracking and more importantly sulfide stress corrosion cracking are encountered. Historically, alloy 625 weld overlay has successfully been used in severe corrosive environments.

INTRODUCTION
The trend in oil and gas production has been towards deeper wells, which has resulted in more hostile environments due to increased temperatures, pressures and the presence of H2S, CO2 and chlorides. Many wrought CRA alloys in the cold worked, or aged condition, have been used for different components (Table 1). There exist many applications where, due to the massive and intricate nature of certain components involved, it is not practical or cost effective to use wrought products. In many cases, the materials with the appropriate corrosion resistance are limited in mechanical properties (Table 2). In such cases, the desired mechanical properties can only be achieved through cold working which are unpractical for many product configurations. For these cases, historically welding has been used to overlay the corrosion resistant alloy on low alloy steel.
The alloy that has extensively been used for such applications has been alloy 625 UNS 06625.
Although alloy 625 has been the primary weld overlay material used in oil field applications, there have been instances where, this alloy under severe sour corrosion conditions and temperatures, has proven to be unacceptable. Another drawback of this alloy 625 has been its limited mechanical properties.

WELDING PROCESS
The gas-metal arc welding (GMAW) process uses a constant power source and continuous wire feed. The wire electrode forms an arc with the base metal and is consumed in the weld pool. The weld metal is protected by shielding gases. Depending on the welding parameters selected, four different modes of metal transfer can be utilized. The four modes of metal transfer that can be used are: spray; globular; short circuiting; and pulsed arc transfer. The protective atmosphere for gas-metal-arc welding is usually a combination of argon, helium and carbon dioxide. The optimum shielding gas will vary with the type of metal transfer used.

SAMPLE PREPARATION/PROCEDURE
Weld overlay samples were prepared using the gas metal arc welding (GMAW) process. The substrate tubes were fully heat treated AISI 4130 with a nominal O.D. of 9" × 6" I.D. × 12" long (23 cm. × 14 cm. × 30 cm.). Welding was performed using alloy 625, alloy 59, alloy 686, alloy 725 and alloy C-22. Single layer and two layer weld deposits were applied to the inside diameter of the substrate tube. For the single layer sample, the deposited thickness was sufficient to achieve a 3 mm minimum clad thickness when the I.D. was machined concentric with the O.D. For the two pass samples, the final machined clad thickness was 9 mm. After welding, a stress relieve was performed on the alloys tubes.
Design Methodology: Code-Driven Design Of Pipelines In Deep Water
Authors: Lawson John 
Published: October 2008

ABSTRACT
The present day approach to writing and presenting Engineering Design Codes and Standards could be measurably improved by adopting a methodological approach to their composition. Current design Methodologies are examined to establish their adaptability to such a role. It is concluded that a multidimensional relationship could be successfully developed in such a way as to integrate the preparation of codes with their intended use as design models. Examples of existing Codes, with a particular emphasis on pipelines for use in deep water, are used to demonstrate one such development. It is proposed that Codes might be produced as stand-alone tools of design methodology and that a new approach to their composition could lead to a more effective, productive and efficient utilisation of their content.

INTRODUCTION
The design of underwater pipelines suitable for the transportation of hydrocarbon products has been going on since before the first pipeline was laid, whenever that may have been. Certainly a few decades have passed since then. Like any other specialist discipline, subsea pipelines have their own peculiarities and they must be properly, rigorously designed to minimise the possibility of catastrophic rupture, with subsequent loss of production, loss of revenue and, above all, the environmental consequences of such an event. Pipelines are being laid in deeper and deeper water as the search for recoverable resources is extended. It is certain that these peculiarities will not became more easily addressed; the reverse is almost certain to be the case.
The pipeline engineer has a number of tools at his elbow to aid him in his design work and to help make sure that the finished product is "fit for purpose". He has a number of codes at his disposal to which he can make reference for guidance on what is considered mandatory and to assist him in evaluating his analyses such that those bodies responsible for the acceptance of the design, including his client, will have confidence in the package which he produces for approval and acceptance. Such Codes include:IP6API RP1111DnV rules8S8010
At his elbow he might also have an in-house set of design guidelines or even a sophisticated suite of software programmes. He might have a mathematical package to do the complex calculations, a graphics package to represent results. It would be even nicer if he had a good, solid design methodology at his fingertips; it would be more economic and less prone to error.
Recognised design methodologies too have been around for a few decades. The latest trend of thought is to marry a design methodology with a software solution, something that has not really been available until the recent advent of affordable, real computing power, currently in the shape of 32 bit, 66 MHz desk top computers.
Debris Protection System For Liner Tops
Authors: Telfer George , Sweeney Dave 
Published: October 2008

ABSTRACT
This paper will introduce a new design of debris protection system for liner tops. The system has been used extensively in the North Sea and has solved the problem of well debris (e.g. formation cuttings/fines, mud solids, cement solids, foreign bodies etc.) entering the liner top P.B.R. and sticking the setting tools.

INTRODUCTION
Well debris entering liner top polished bore receptacles (P.B.R.'s) during cementing operations has been a notorious problem for many years, and in some cases has led to liner banger setting tools becoming stuck in the liner top P.B.R. This can lead to the setting tool being cemented in place and result in an expensive fishing job or side-track. This paper will describe how Enterprise Oil experienced severe problems with well debris entering the liner top P.B.R. and sticking the liner hanger setting tool, In addition, it will describe how a prototype debris protection system was developed and tested prior to offshore application, and the subsequent successful use of the tool on Nelson development wells.

DESCRIPTION OF PROBLEM
During drilling of the early Nelson development wells in the UK North Sea, severe problems were experienced with well debris entering the liner top P.B.R. As a result, difficulties occurred retrieving the liner hanger setting tool. Although in all cases the setting tools were successfully recovered, it was evident that there had been a significant risk of cementing the liner running string into the liner top P.B.R.
In all cases, the well debris entering the liner top P.B.R. consisted of fine cavings of shale originating from the base of the Balder formation (see fig. 1). The setting depth of the 9.5/8" casing strings on Nelson development wells is governed by two factors, these being :The Eocene formation must be cased off prior to drilling the Forties formationCasing must be set prior to drilling into a loss zone. 85 feet TVD below the top of the Balder formation.
The Eocene formation consists of highly reactive and over-pressured shales which become unstable if drilled with mud weights less than 14.0 ppg, and the Forties formation is normally pressured sandstone in which differential sticking may occur if drilled with mud weights above 10.0 ppg. Therefore, to allow the Forties sandstone to be successfully drilled without inducing borehole collapse in the Eocene, the 9.5/8" casing string is set in the Balder formation. In addition, the Balder also contains a known loss zone when drilling with 14.0 ppg mud, above which the 9.5/8" casing must be set. These criteria dictate the setting depth of the 9.5/8" casing shoe. Having run and cemented the 9.5/8" casing string, the 14.0 ppg mud used to drill the 12. ¼" hole section is displaced to 10.0 ppg mud prior to drilling the 8. ½" hole section.
Dynamic Characteristics Of A Pipeline Dewatering Train
Authors: Hamid Syed , Falck Christian , Wissing Marcel , Grotberg Ingvar 
Published: October 2008

Abstract
Gas- or liquid-driven pig trains are sometimes used during pipeline dewatering before the line is commissioned for gas transport. Pig trains consist of compartments of drying liquid separated by sealed mechanical pigs. Gels may be used in the front and the rear of the train for various purposes, such as minimizing gas bypass, providing seal lubrication, etc.
Train operation is controlled by modulating the supply gas pressure and controlling the water discharge with a valve opening at the downstream end of the line, The valve opening schedule determines the pig train's rate of acceleration. A very fast opening schedule results in high hydraulic transient pressures that may cause rapid velocity changes. An opening schedule that is too slow would cause "start-stop" or "jerky" pig movement, which could result in forward gas bypass. Both of these effects tend to degrade train performance.
To help estimate the characteristics of a pig train for a given operating schedule, a numerical simulator has been developed. This simulator incorporates mathematical models of the pigs, the fluid compartments, the pipeline geometry, and the downstream control valve. The fluid compartments and the liquid portion of the pipeline are modeled with the method of characteristics while taking into account the non-Newtonian character of the gel rheology. Coulomb friction along with stiction is used to model the pigs.
The simulator has been used to design dewatering train startup and shutdown schedules for two methanol swabbing operations involving two subsea Zeepipe pipeline systems: one 814 km (505 mi.) long and the other 250 km (155 mi.) long. These trains have consisted of several pigs with methanol and gel compartments. Unscheduled abrupt shutdowns have also been simulated. The methods developed can be applied to the general case in which pigs are used for fluid separation.
The performance of the two actual pipelines illustrates the significance of the new approach relative to the startup and shutdown of pig trains in general.
This paper describes the dynamic mechanisms involved in pig trains and abolishes certain intuitively developed paradigms, such as starting a train "very slowly" to minimize the hydraulic transients.

Introduction
Pipelines are normally hydrotested for mechanical integrity either after a repair job or after the initial installation. After hydrotest have been performed, a line is dewatered and dried before it can be commissioned for gas transport.1,2
A dewatering system involves a displacement fluid supply, a dewatering train, and a valve for water flow rate control (Fig. 1). The dewatering train takes up different configurations depending upon the size of the pipeline. In pipelines shorter than 50 km (30 mi.), a small number of mechanical (foam or wiper seal) pigs can be driven with nitrogen or air, Sometimes produced gas is used to displace the train.
The Albacora Field Subsea Development: A Case History
Authors: Bastes B.L. 
Published: October 2008

ABSTRACT
Subsea technology has proved itself as an alternative for marginal or deep water field developments. This paper will describe six years of operational experience on the Albacora field, an important subsea development project being carried out offshore Brazil. Main results and major difficulties encountered during this period will be discussed in the text.

INTRODUCTION
Albacora is one of the last decade discovered deep water giant fields, located at Campos Basin, offshore Brazil. Being explorated since 1968, Campos Basin became the main petroleum province in Brazil. Ranging from shore to 3,400 m WD, with a total area of 110,000 Km2 its total proved reserves, in WD u; to 1,000 m, reaches 2.78 X 109 barrels of oil and 58.2 × 109 std m3 of gas, 16 % of this being located in the Albacora field (Fig. 1).
In 1984, with the wiIdcat well 1RJS297, drilled at 293 m WD, the Albacora field was discovered. Further efforts led to the knowledge of the field's full extension, which is presently accepted as covering an area of nearly 235 Km2. Since this first discovery and the following successes in Marlin field, the basin development strategies had been reviewed to attain those new chal Ienges in deep waters.

GEOLOGY OF THE ALBACORA FIELD
The Albacora field is located nearly 110 Km from the coast, in water depths varying from 230 to 1600 m. Its main oil occurrences are found in the Tertiary / oligocene, Eocene and Miocene sandstones (Campos/Carapebus) and in the Cretaceous/Albian sandstones (Macae/Namorado), all of turbiditic origin (Fig.2). A total of eight different oil reservoirs ranges from 2350 to 3260 m TVD, with a significant variation in porosity, water saturation, oil gravity, etc2. Its proved reserves are of 0.455 × 109 barrels of 26/29 °API oil and 8.48 × 109 std m3 of gas.

FIELD DEVELOPMENT MILESTONES
To cope with geological and reservoir uncertainties, as well as technological limitations and budget requirements related to the deep water / giant field combination, it has been planned to develop the Albacora field by stages. Each stage provides reservoir data, technology field testing and early cash flow to support the following stages3,4,5. The project's milestones are listed bellow:1984 - Drilling of the well 1RJS297, discoverer of the field;1987 - Drilling and successful testing of the well 1RJS367 at 1565 m WD, a world record;1987 - Phase 1 (Pilot System) start-up: The Pilot System comprised 6 wells connected to a diver assisted subsea manifold, producing to a FPSO consisted of a tanker (P.P. Moraes) and a monobuoy in SBS configuration, at 230 m WD. This conception combines a CALM type monobuoy rigidly connected through a yoke to the tanker. OiI sales were conducted through the SBS monobuoy to a shuttle tanker tied to a second monobuoy.
Deepwater Production: 1950-2000
Authors: Dunn F.P. 
Published: October 2008

INTRODUCTION
A tension leg platform was just recently installed in the Gulf of Mexico in almost 3000 feet of water. How did the industry get there? Possibly more significantly, how much deeper can we go, and when? I will try to answer the first question by reviewing the history of offshore operations, and I'll then make a stab at answering the other two questions.
In addressing the first question, I will focus primarily on technical developments over the past 40+ years in several areas: knowledge of the environment, e.g., oceanography, hydrodynamics, meteorology, and to a less extent, seismicity; analysis; design; soil mechanics/ geotechnology; materials; construction; and instrumentation, testing and calibration. Of course, overshadowing all of these subjects is economics-the bottom line-but my emphasis will be on the technical areas.
I will concentrate on steel drilling/production structures in the Gulf of Mexico and Offshore California, fully realizing that concrete structures have played and will play a significant role in deep water, certainly in the North Sea, and quite possibly in the Gulf of Mexico in the future.
I have divided the fifty-year period somewhat notionally into five segments: The Beginnings; The Learning Curve; Maturity; Alternatives; The Future.

THE BEGINNINGS
One of the first offshore drilling operations took place in 1938 in 18 feet of water, about 1-1/2 miles offshore Texas, from a wooden deck platform supported by 100 timber piles, each 65 feet long. A long trestle to shore, supporting railroad tracks, supplied the platform.
The first "permanent" steel platform (the timber platform noted above was severely damaged by a 1938 hurricane) was installed in 1947 offshore Louisiana in 20 feet of water. The platform employed six templates and was supported by 267 piles made of 8-inch and 10-inch pipe.
The design and construction of such steel platforms were dictated by available sizes of structural members and by existing construction equipment (70-ton crane). Design wave height in 1947 was 32 feet, upped to 40 feet in 1949 when a hurricane hit the Texas Coast. Design wind velocity in 1949 was 125 miles/hour. Wave forces were calculated based upon a chart using solitary wave theory. The forces were less than 1/3 of those which would be used today. Foundation design was based upon a series of seven core tests, some taken to 400 feet, along the eastern Louisiana coast. Pile driveability tests were also conducted to 165 feet of penetration.
By 1953, seventy steel platforms had been installed, the deepest in 70 feet of water. In 1955, a platform was installed in 100 feet of water, followed in 1959 by the installation of a 4-pile "minimum" platform in 204 feet of water.
Major advances during this period were in the area of installation equipment. A 150-ton derrick barge specifically built for offshore use was available in 1950. By 1953, another barge of 250-ton capacity was in service. Platforms were lifted into place by the crane, not launched. If the platform weighed too much for one crane, two were used.
Welding And Ndt Development In Support Of Oman - India Gas Pipeline
Authors: Even Thomas M. , Laingv Brian , Hirsch Dan 
Published: October 2008

ABSTRACT
The Oman to India gas pipeline is designed for a maximum water depth of 3500 m. For such a pipeline, resistance to hydrostatic collapse is a critical factor and dictates that ery heavy wall pipe be used, preliminarily 24 "ID × 1.625" wall. Because of the water depth, much of the installation will be by J-Lay which requires that the Joint be welded and inspected in a single station. This paper describes the results of welding and ND T test programs conducted to determine the minimum time to perform these operations inheavy wall pipe .

INTRODUCTION
The Oman Oil Company is implementing the Oman to India gas pipeline project. The offshore section of this pipeline is 1139 Km long, between Ra's al Jifan in Oman and Rapar Gadhwali in India, in water depths up to 3500 Meters, Approximately 80?40 of the pipeline route will be in waterdepths where heavy wall pipe is needed to resist hydrostatic collapse, and the J-Lay technique will most likely be used for installation, Using the J-Lay technique equires that joint alignment, welding, inspection and coating all be performed in a single station. Minimizing the time required to perform these operations will have a significant impact on overall construction costs and schedule.
An Industry Review was conducted to identify methodsthat would satisfy the initially projected requirement of 45 min. to complete both welding and NDT. Two welding methods were selected from the review groups to perform the welding test program and four non-destructive methods were selected for the NDT test program.
This paper reports the results of these test programs and indicates areas within each operation where further work is desirable.

SUMMARY
Two companies, one using a modified form of GMAW and the other using automatic GTAW with a hot wire feed, were contracted to perform the welding tests listed below,Develop a welding procedure for the 2-G position on26"OD × 41.3mm wall pipe.Demonstrate the procedure on a single weld.Make a series of three consecutive welds, each weld in under 38 minutes.
Both welding systems used a narrow gap technique that, when employed by three units equally spaced around the pipe and welding in unison, was able to complete the weld in under the goal of 38 minutes. The narrow groove minimized the amount of filler metal required, so that welding parameters approaching the maximum deposition rate could be developed.
This report provides details of each welding procedure including filler wire, shielding gas, travel speed, arc parameters, and joint design.
Four companies were selected to perform the NDT portion of the program as follows:Develop a NDT procedure for inspection of 26" OD × 41 .3mm wall API X60 pipe weld in the 2G position.Demonstrate the procedure cycle time,
The processes used for this work are; Film radiography, Real Time Radiography, Mechanized ultrasonic testing(Pipeline system), and Mechanized ultrasonic testing (Pressure vessel system).
The Suction Mooring, A New Type of Offshore Single Point Mooring
Authors: Korsgaard Jens , Hutter Louk 
Published: October 2008

ABSTRACT
Existing systems for mooring offshore oil production vessels of the ship type only permit the mooring or tying up of the vessel in quite lowwave conditions. Virtually all existing systems do not permit the vessel to moor in wave conditions exceeding H. = 4.5 m. Most systems require wave heights smaller yet to moor. This is a problem in cases where frequent mooring operations are required such as for shuttle tankers and for disconnectable oil production or storage vessels moored in areas with a high incidence of tropical storms. The wait for the waves to subside following the storm causes additional production losses due to the oil field being shut in.
A newly developed mooring system, the suction mooring, promises to overcome this problem by permitting the mooring of the vessels in wave heights to at least H= = 8 m. The principle of the mooring consists of using the hydrostatic pressure available at the keel of the vessel to press a mooring buoy onto the bottom and holding the vessel by the resulting friction. The action of the mooring buoy is similar to that of a suction cup.
The pressure above the buoy is lowered and maintained low by means of pumps aboard the vessel.
This paper reports on model tests carried out to prove the feasibility of conducting the mooring operations in high waves. Three different configurations of the mooring buoy were tested. For two of the configurations it was found that the mooring process could be carried out safely in all wave heights tested i.e. up to H. = 7.7 m.
The impact upon offshore operations of this capability was investigated by performing Monte Carlo simulations on a hypothetical oil field in the center North Sea and in the northern North Sea. An actual center North Sea wave record was used in the simulations.
The suction mooring system was compared to two other high performance mooring systems. The results show that weather related oil field shut-ins re reduced an order of magnitude by application of the suction mooring compared to the other systems simulated.

MOORING PRINCIPLE
The suction mooring principle involves mooring a submersible buoy to the bottom of a vessel utilizing differential hydrostatic pressure, in a manner similar to a suction cup.
A mooring buoy is brought into contact with the flat portion of the bottom of the ship either by means of a retrieval line such as commonly usedfor the Buoyant Turret Mooring (BTM) and Submerged Turret Loading (STL) type mooring or by means of reduced buoyancy utilizing a system aboard the buoy to control the buoyancy.
The reduction in hydrostatic pressure above the buoy is provided by pumps aboard the ship. A bow thruster pump of the Omni-thruster or the Elliott Turbo Machinery type having its intake at the keel in the mooring area is used to achieve the initial pressure reductions. This type of pump has a capacity from 4 to 11 m 3 /sec.