bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bearing Capacity Of Driven Model Piles In Dense Sands From Calibration Chamber Tests
Authors: Foray P.Y. , Colliat J.Y. , Nauroy J.F. 
Published: October 2008

ABSTRACT
Model piles were driven and tested in samples of dense siliceous sands in a large calibration chamber at 3S/lMG, Univ. of Grenoble (France). Tension and compression tests were performed with both open-ended and closed ended pipe piles. The research programme aimed at providing geotechnical engineers with design parameters for piles driven into dense sands, focusing on points of interest for offshore piles, in particular:dense to very dense sands,tension versus compression skin friction capacity,high confining pressures (up to 800kPa) for simulating large penetration depths.comparison with cone penetration tests.
New design parameters are proposed for computing bearing capacity of piles driven in dense to very dense siliceous sands. They are compared with those given in the current API RP2A recommendations.

INTRODUCTION
Bearing capacity of offshore piles driven in dense siliceous sands has been, and continues to be, a controversial topic since API RP2A recommendations were changed in 1984 (1). The two main points of concern, relating to K values for compression and tension pile capacity and limiting values for skin friction and tip resistances, have a direct influence on offshore foundation costs as reflected by steel cost, driving equipment mobilization cost, installation time and cost for possible remedial measures. These changes are still not fully accepted and applied for the North Sea by certifying authorities and some geotechnical consultants preferring to adhere to the more conservative rules of API 82.
It is generally agreed that the uncertainty on computed axial capacity of piles driven in sands is large when using current API recommendations, and a statistical pooling of international experts concluded that the API criterion may be conservative by 20 to 40%. In dense to very dense sands (2), This is of particular concern for the North Sea where dense sands are encountered widely and where potential savings are important due to the large number of structures involved.
On the other hand, some studies (3,4) have indicated a tendency of the API method to under predict capacity of short piles and over predict that of long piles, due to the so-called "friction fatigue effect". Interesting contributions were made recently by Kraft (5,6) and by Randolph and Dolwin (7) where new design criteria were proposed for computing axial pile capacity in sands, considering that no data provided conclusive evidence of the existence of limiting values and that an optimistic K value of 0,8 leads to the over predicting of the capacity of short piles when using the API criterion (5,6). It is also suggested that the current API design method may be conservative mainly due to underestimation of the end bearing capacity of piles (7).
In an effort to improve our knowledge of the behaviour of piles driven in sands, an extensive experimental programme was conducted at 3S/lMG and supported by ELF Aquitaine Production and IFP. Model pile tests were performed in a large calibration chamber
Case Study Of Offshore Pile System Reliability
Authors: Tang W.H. , Gilbert R.B. 
Published: October 2008

ABSTRACT
This paper presents the results of research effort to evaluate the reliability of offshore pile foundation systems. It is an extension of previous work by the authors [14] dealing with the reliability of individual piles under axial and lateral loading. The reliability of the pile system is evaluated for three ease study platform designs, and the level of reserve between initial failure of an individual pile within the system and system collapse is studied. The results of this research are valuable in providing insight into the reliability achieved with current design procedures and the factors which affect the performance of the foundation system. The results should facilitate the development of reliability based design procedures which provide for a consistent level of safety between different site conditions, loading conditions and pile configurations.

INTRODUCTION
Satisfactory performance of pile foundations for offshore oil platforms is an important consideration in design, and a better understanding of the reliability of platform foundations is important as design practices move towards reliability based systems. Evaluation of pile system performance is influenced by various sources of uncertainty including uncertainties in system loads, pile properties and soil properties. In addition,. uncertainty is associated with the inability to predict performance using simplified models of actual behavior. These uncertainties have traditionally been accounted for through a variety of conservative design practices extreme loading conditions are use~ soil properties are conservatively selected; deterministic safety factors are applied to the design, and design is often based on failure of the most heavily loaded pile in the foundation, not failure of the entire pile system. AH is currently in the process of formulating a reliability based design procedure for fixed platforms. The primary advantage of this approach will be to achieve a consistent level of performance reliability in platform design between different site conditions, loading conditions and piIe configurations.
In formulating a reliability based design procedure, the following questions arise:What level of reliability is achieved for an individual pile and for the pile system using traditional design methods?How do the various sources of uncertainty affect the reliability of the design?How much redundancy or reserve between initial failure and system collapse is built into the design?
Since 1986, a series of research projects has been sponsored by API to address these questions. Findings from the first two phases, which deal with the reliability of individual piles under axial and lateral loading, are summarized in [14]. The third phase concentrates on the reliability of the pile system and the relationship between the performance of individual piles within the system and the performance of the system. Details of this research are reported in [15], and the results are summarized herein.
Stress Corrosion Cracking Of Duplex Ss, (Jns S81803 On The Gyda Hp Separator
Authors: Øystetun Ingar , Johansson K.A. , Andersen O.B. 
Published: October 2008

ABSTRACT
The duplex SS HP separator on the BPN operated Gyda platform suffered external SCC after 1 1/2 years in operation. The cracking occurred in two circumferential welds. Conditions creating SCC were seawater sustained in wet insulation, high residual stresses from welding and surface temperatures in the range from 40-100°C.

INTRODUCTION
The Gyda Platform, located in the Norwegian sector of the North Sea, is a single steel jacket PDQ platform (production, drilling and quarter) and is operated on behalf of the licensees by BP Norway Limited U.A.. Oil Production commenced in June 1990, therefore the HP separator had only been in operation for 18 months prior to the occurrence of the failure.
Fig. 1 shows an overall schematic of the production process on Gyda. The produced fluid from the wells flow to the production or test manifolds prior to entering the single production train or the test separator. The produced fluid then pass through two stages of three-phase separation where oil, gas and water are separated. The first stage is the HP separator, the second is the LP separator, respectively operating at 26 and 15 barg pressure. The oil stream is cooled between the two stages.
The HP separator design parameters are listed in the table no. 1.
The process plant is designed to handle a maximum of 70,000 STB/D of crude oil.

CRACK OBSERVATIONS
On 01 January 1992 a small leak of water was detected below the HP separator.
On 02 January an investigation team started the failure examination cm Gyda. With the removal of the insulation it was identified that cracks were clearly visible in the lower part of the vessels at the two central circumferential girth welds and at the oil outlet nozzle. After extensive NDE the following main cracks were identified (see fig. 2); 5 cracks on weld no. 1007, 25 cracks on weld no. 1008 and 12 cracks on the oil outlet nozzle (N3A). The maximum crack length was 230 mm, but the majority of the cracks did not penetrate through the vessel shell thickness. All the cracks were observed as being below the produced water/oil interface evel.
Fig. 3 illustrates the condition of the lower part of the vessel after removal of most of the insulation. One of the major and penetrating cracks is visible at the centre of the photograph. In addition there were brown corrosion products and salt deposits with evidence of pitting corrosion. The insulation was found to be soaked with water along two thirds of the vessel bottom, including all the areas where crocks were detected.
During the course of the inspection of all three separators, different NDE techniques were used with varying degree of success. Dye penetrant inspection (DPI) is a recognised method of NDE of duplex stainless steel. However, the Gyda experience showed that a rather long soaking time was required to detect the cracks. Internal cracks were very difficult to detect.
Snorre Project Execution: Lessons Learned
Authors: Solheim B.J. , Plummer F.B. , Gjerso Pål 
Published: October 2008

ABSTRACT
The Snorre Field is the first truly deep-water development in the North Sea. It consists of the largest tension leg platform yet installed and a large, 20 well-slot, remote subsea production system. The platform went on production in August 1992 more than one month ahead of schedule and under the original budget.
The execution of projects with a high content of new technology can provide special challenges. The five Snorre papers are meant to provide feedback to the industry on how these challenges were addressed. They essentially pick up where the papers presented at the 1991 OTC left off (Ref. 1–6). This paper looks at the project execution, as a whole, while the others focus on specific topics such as installation, operations preparation, start-up, some innovative quality assurance approaches, and subsea experience.

INTRODUCTION
Over the past 15 years, a body of project management technology has developed in Norway which is suitable for managing large complex offshore platform developments. The Snorre project built on this foundation and added new techniques in the area of managing the development of new technology (required for deep-water) and in the area of technical risk management. While this is not the only way to execute large offshore projects, it has proven effective. It is expected that some of the principles will be valid elsewhere, as well.
This paper covers the overall strategies used by the Snorre management team. It then lists certain factors which have contributed to success, and areas for improvement, for each of the project phases. It is written in a point-outline format to make the key issues more readily visible and, hopefully, serve as a handy reference.
It concentrates on the lessons learned for the TLP itself. The Snorre marine operations are covered in some detail in OTC paper 7218. However, for completeness, the main lessons relevant to the TLP are included here as well. Likewise, the Snorre TLP operating experience is detailed in OTC paper 7220 with only the relevant experience highlighted here for completeness.
The subsea production system land test and installation experience is covered in a separate paper (OTC 7221) and will not be addressed here.

CONCEPT
The Snorre Field is located in blocks 34/4 and 34/7 in the North Sea, about 200 km west of Florø on the Norwegian west coast. Saga Petroleum is the operator and the other owners are Statoil, Esso, Deminex, Idemitsu, Norsk Hydro, Elf Petroleum Norge A/S, Amerada Hess, Enterprise Oil and DNO. Phase 1 of the Snorre Field development consists of a Tension Leg Platform (TLP) in steel and a Subsea Production System (SPS) (see Fig. 1). The water depth varies from 310 to 335 metres. Both installations are the largest of their kind in the world today. About 40 wells will be drilled from the TLP and 10 wells from the SPS with the possibility of another 10 wells if required. Oil and gas from both installations are part-processed on the TLP and shipped via pipelines to the Statfjord A platform, 28 km away, for final processing.
Technology For Full-Range Water-Cut Measurements
Authors: Scott B.N. , Cregger B.B. , Shortes S.R. 
Published: October 2008

ABSTRACT
The ability to measure both water and oil continuous phases of a production stream from 0% to 100% water cut has been pursued by a multitude of companies for many years with marginal success in transferring the technology to practical use.
A field worthy technology developed for accurately determining the full range of water-in-oil (0-100% water cut) for production and well testing will be covered. Information about the fluid phase, oil or water continuous, is determined and given in real time. The novel technique used is called oscillator load pull, which detects the permittivity of the fluids. Salinity, temperature, entrained gas, and emulsion type effects will be discussed showing their effects on phase inversion and measurement parameters. Data from installed instruments on location in Alaska and the lower 48 states will be shown. Comparisons to shake-outs and well test logs will be compared. Descriptions of how the real time information of the phase of the fluids has been used to observe and affect well management will be presented.

INTRODUCTION
The accurate measurement of the water content in crude oil has been an ongoing problem in both the low water cut (0-4% water in crude oil) and the full cut range (0-100% water). These problems existed due to the limited sensitivities of earlier measurement methods and the conductivity of salt water which both limits the sensitivities available and makes the determination of the phase of the fluids a necessity.
A typical use for a full range water cut instrument is in well testing. The use of a full range instrument allows the use of only a two phase separator which reduces the size and complexity of the well test equipment while improving the reliability of the measurement. Since the entire fluid stream is measured at once and a totalizer tied to flow meters can give the net oil, the separate tracking of the water and oil legs is eliminated. The separate oil and water tank level controls are eliminated along with the associated errors with oil/water carry over to the water/ oil legs.

THE FLUID PHASES OF OIL AND WATER
An emulsion is a dispersion of one liquid in another where the continuous or external phase is defined as the matrix in which the droplets are suspended. The droplets which are surrounded by the continuous phase are called the discontinuous or internal phase.' The two types of emulsions will be abbreviated OIW for oil-in-water (water continuous) emulsions and W/O for the water-in-oil (oil continuous) case.
Generally, a well begins by producing W/O emulsions until water injection begins and the water cut increases over time to 70% or above. The point at which the well will produce water emulsions depends upon the emulsifier contents of the crude oil. Under laboratory conditions, West Texas crude oil will invert from W/O emulsions to O/W at approximately 88% water at 80 degrees F while injecting 5% salt water.
The Troll Olje Subsea Development Concept
Authors: Bakken Christian , Liverud Arne 
Published: October 2008

ABSTRACT
As a part of the Troll Olje Development the Subsea systems will be one of the largest developments to date to be installed. Norsk Hydro 's experience from the previous subsea projects has materialized into the concept for Troll Olje.
All contracts for equipment have been placed and installations will start early 1994 and finish medio 1997.
This paper will describe the subsea system, highlight some technical challenges and elaborate on the contract strategy.

INTRODUCTION
The subsea production system is based on a cluster concept, satellite wells tied back to manifold centres. The manifold centres are tied back to the floating production unit (FPU) via a production riser base. Figure 1 shows the subsea facilities layout and Figures 2 and 3 show it schematically.
The wells of each cluster are connected to a manifold centre via a flexible flowline and an infield Integrated Service Umbilical (ISU). The infield ISU contains control and power functions, a service line and a scale inhibitor line.
Parallel gathering lines and production risers transport produced fluids from the individual manifold centres to the FPU via the production riser base. Each manifold is connected to the production riser base by a main ISU which is connected to the FPU by a riser ISU. These ISUS have the same contents: control and power functions, a service line and a scale inhibitor line.
The only valving on the production riser base is associated with the gas lift system. A single gas lift umbilical riser provides lift gas to the riser base where it is distributed to each production riser.
A gas injection well is located in the southern Oil Province. It receives injection gas via a dedicated flexible injection line/riser from the FPU and is controlled/serviced through an infield ISU from a manifold centre.
A separate riser base is provided for the gas and oil export products. A single oil export riser connects to a steel pipeline which transports the oil to shore, A single gas export riser connects to a steel pipeline which transports the gas to the Troll Phase 1 platform where it will be combined with the Phase 1 gas and pipelined to shore.

SYSTEM DESCRIPTION

General Functional Requirements
The Troll Olje field design production rates are 25,000 Sm3/sd of oil, 40,000 Sm3/sd of water and 65,000 Sm3/sd of total liquids, Production from individual wells may be as high as 6,000 Sm3/sd but rates are expected to average around 3,000 Sm3/sd. Production fluid gas-oil ratio (GOR) will vary between 60 and 300 Sm3/Sm3 but certain wells may be produced as high as 2,000 Sm3/Sm3 in order to maintain gas production.
The reservoir pressure is 159 bara at the datum of 1547 m mean sea level (MSL). The corresponding temperature is 68°C. The flowing wellhead pressures will vary considerably due to decreasing reservoir pressure and the expected wide variation in water cut and GOR. The maximum shutin wellhead pressure is 143 bara.
Buckling Of Pipe And Tubing Constrained Inside Inclined Wells
Authors: Chen Yu Che , Adnan Sarmad Che 
Published: October 2008

ABSTRACT
This paper presents a new approach to predict the buckling behaviors of a drill pipe constraint in an inclined well. The relationship between the MU pipe configuration along the well and the external load applied to the pipe is investigated. Different models of buckling behaviors are verified. Our work is a general approach since several factors such as the gravity and the hole inclination are included in this analysis.

1. INTRODUCTION
Helical buckling is an important parameter for drilling process. The phenomenon of helical buckling was first investigated by Lubinski1,2et al. and led to the well-known helix pitch/force relationship, which was subsequently used by other3. These analyses assumed that the weight of the drill pipes or tubular are negligible compared with externally applied forces. Another important phenomenon for the initiation of the buckling was investigated by Paalay et al.4 and Dawson et al.5 Their analyses showed that a drill pipe will initially deform into a sinusoidal configuration along the low side of the hole. Later on, Chen et al.6,7,8 extended their results and showed that for horizontal holes, the already buckled drill pipe will change its configuration from a sinusoidal wave into a helix as the axial force increased. The axial loads associated the initiation of the sinusoidal and helical forms of the drill pipe are derived and confined experimentally. For these previous research, the drill pipes are either assumed to be weightless or are lying in a horizontal holes where the weight of the drill pipes does not affect the axial load along the pipes.
Our current analysis is based on the work by Cheatham3et al. and Paalay4et al. We consider the influence for the weight of the drill pipe on its configurations and investigate the stability of the drill pipe using energy method9,10We find that gravity influences the buckling of a pipe in two ways. Firstly, the axial component of the weight increases the thrusting force at the bottom of the hole and speeds up the buckling process. On the other hand, the radial component of the weight of the pipe acts as spring constant for an elastic foundation that resists the buckling of the pipe. A general form for the heliea.1pitch-force relation is reached and the transitional behaviors of the pipe between different buckling modes am investigated.

2. PIPESINHORIZOIWALWELLS

INTIATION OF SINUSOIDAL DEFORMATION
The initiation load for a long pipe deforming into a sinusoidal wave in a horizontal well was given by Dawson and Paslay5 based on Paslay and Bogy's4 work. This equation is written as (Mathematical equation) (available in full paper)
For a long pipe, we can set /=L/n½ in Eq. 1 and the critical load is similar to the buckling force for a beam on an elastic foundation9 with the foundation constant k=w/r.