bluuebunny/crossref_metadata_2025 huggingface dataset:
Prediction of Pipelaying Equipment Performance In Hostile Environments
Authors: Pearce B.K. , Kishpaugh J.A.
Published: October 2008

In order to predict the performance of pipelaying equipment in hostile offshore environments and to establish incentives for the development of new equipment and techniques, we have developed a computer model that simulates the pipelaying process. Use of this tool has shown quantitatively that semisubmersible laybarges should be cost effective in rough water areas such as the North Sea. Simulation results also quantify the advantages of using automatic welding and wide-truss stingers.

The computer simulation model is designed to predict probable installation costs and times for completing offshore pipeline construction projects, taking into account not only work interruptions due to weather, but also equipment failures, and other randomly occurring events such as pipe buckles and weld defects. The Monte Carlo simulation technique is used to model the occurrence of these uncertain events. By making a large number of simulations of a pipeline construction project, installation time and cost predictions can be made on a statistical basis; i.e., probability distributions of installation time and cost are developed for the project.

This paper describes the computer simulation program, shows how it, is used, and presents some equipment evaluations for the northern North Sea and the Grand Banks of Canada.

INTRODUCTION

Over the past few years a number of ideas for improving offshore lipelaying operations have been suggested including the use of laybarges with better motion characteristics, faster pipe joining methods, and improved stinger designs. However, the advantages of such proposed improvements have not previously been quantified in terms of potential savings in construction time and cost. It is difficult to do this because of the fact that it is simply hard to predict the performance of any particular piece of pipelaying equipment. This is true primarily because of the influence of weather on pipelaying operations and because there is not a one-to-one-correspondence between downtime and inclement weather. However, in addition to weather downtime, pipe abandonment and recovery times must also be accounted for, as well as downtime for mechanical failures and pipe damage.

In order to account for these uncertainties, we have developed a computer model that simulates the pipelaying process by using the Monte Carlo technique2, 3 This is a "probabilistic" estimating approach and provides not only a single-valued, best estimate of pipelaying performancebut also gives additional information, i.e., (1) a measure of how much better or worse results might be and (2) the risk associated with any particular estimate. Monte Carlo simulation is being widely used for analysis of problems involving uncertainty.

The pipe1aying simulation model provides a means of (1) estimating pipeline construction time and c8st (2) selecting pipe1aying equipment, (3) evaluating contractor bids3 and (4) quantifying the potential advantages of proposed improvements.
Subsea IOR: Keynote Introduction
Authors: Utseth Rolf H. , Strøm Steinar
Published: October 2008

Statoil, as a major offshore operator, has established demanding ambitions with respect to increased oil recovery from our subsea fields. We see a large gap, appr. 15%, in recovery from our fields produced from fixed platforms relative to the subsea developed fields, even though the quality of the reservoirs is basically the same. To a large extent this gap is related to the high cost in subsea operations in general and well operations in particular. This paper includes:A listing and brief introduction to the technologies being developed and implemented.A generic evaluation of how the technologies will influence on the recovery from Statoil's existing subsea fields

The paper will act as a bridging document between the other presentations and papers in the joint Statoil/FMC session at OTC 2007.

Background

Statoil envisages fulfilling the demanding requirements to significantly improve the oil recovery from subsea fields. Statoil's current average oil recovery from subsea fields is 45,1%, which is high compared to other operators. The recovery from our platform developed fields is close to 60%. The ambition is to increase the recovery from subsea fields to 55% by 2008, meaning that by 2008 the 55% ambition should be reflected in the resource plans for each individual asset summing up to 55% as an average within the company. Statoil has its current focus on the Norwegian Continental Shelf (NCS), the applicable technologies however are highly relevant also for other parts of the world, such as in deep waters and arctic areas.

The current cost level in subsea drilling and well operations is determined as probably the main obstacle to increase the oil recovery. Consequently, the efforts are to a large extent focused in this area. Statoil has incorporated Riser less Light Well Intervention (RLWI) as a corporate service across asset borders. We intend to do the same with Through Tubing Rotary Drilling (TTRD) in subsea wells, the operations will commence in 2007 utilising the dynamically positioned rig Stena Don.

The next step will be to develop the next generation of subsea wells (Subsea MMX) to significantly reduce the cost of a new well together with sufficient flexibility to tie in new wells over time. Along with the subsea system itself, it is essential to focus on the drilling and well solution and ultimately the rig solution (light unit).

Other technologies such as Subsea Processing and Wet Gas Compression are also very important technologies that are being developed.

The ambitions and deliveries

General

Based on experience from platform operations Statoil has established goals and ambitions within the subsea segment. The R&D focus areas are shown in figure 1.

Figure 1: Statoil R&D focus areas within the subsea segment(available in full paper)

There are ambitions linked to each of the focus area, these are:Identify drainage points and intervention needsLow cost drainage pointsLow cost well interventionIncreased fluid handlingReduced wellhead pressureIntegrated operations
Selection of Routes For Sub-Mediterranean Pipelines
Authors: Serpas Luis B. , Belazoug Amar B. , Matteelli Rolando B.
Published: October 2008

This paper deals with the planning, the execution and the data gathering operations ofa marine survey in the Strait of Sicily and the ultimate objective of determining a path or paths where it could be feasible to construct pipelines across the Mediterraneanbetween North Africa and Sicily establishes the scope and defines the principal tasks and their sequence to accomplish the objectives. A brief summary is given of the operations performed by the survey fleet and presents the techniques and general instrumentation used. A brief analysis is made CO of each one- of the investigative operations, including oceanography, hydrography, hydrology, geology soil mechanics and mefeorology. The description of operations includes the establishing and operating- of the horizontal control system and the photographic techniques employed for the study of the bottom morphology and nature of soils. The paper gives the type of results obtained and the subsequent plottings for use in the analysis of the crossing. The route analysis which was followed for the paths determination is given, together with the methods used to find and select the preferred corridors. Finally, the paper concludes on the results, the applicability and the reliability of the data and its usefulness to the project.

INTRODUCTION

The proposition of transporting natural gas or liquid petroleum from North Africa to Europe via pipelines across the Mediterranean Sea has been discussed, promoted, studied and experimented by many during the last fifteen years. Many energy entities and engineering companies have dealt with this project in various degrees of detail, including a series of full scale experiments intended to demonstrate the feasibility of installing the pipelines in the deep waters of the Western Mediterranean.

It was not until SONEMS, a study company formed by SONATRACH of Algeria, Ente Minerario Siciliano (EMS) and Ente Nazionali Idrocarburi (ENI) of Italy, decided to proceed with an intense techno economic study of feasibility, that such project assumed its imminent charactel' of today. Such project had the specific task of studying the transport of natural gas from Algeria to Italy by a pipeline traversing Algeria Tunisia, the Strait of Sicily, Sicily and the Strait of Messina. Not much was known of the Sicily, especially about the area in the known as the Tunisian Trench. The available charts and existing technical documentation even those as yet unpublished, showed a blank in this area in practically all respects. Among the decisions made by SONEMS, with Bechtel Incorporated as its engineer, was to proceed without delay on a two-phase program:A preliminary feasibility study to be based on a field reconnaissance of the Strait of Sicily.A final in-depth study to be based on a detailed marine survey of the Strait of- Sicily and the Strait of Messina.
Super Jack-Up Type Mobil Drill Rig Platform For Operation In 500 To 600-Ft.Water Depths
Authors: Giblon Robert P. , Minorsky Vladimir U.
Published: October 2008

The developing energy crisis and the resulting need to discover oil and gas producing areas that are under 300 to 600- ft. of water has pointed to the need for a stable mobile drill rig platform that can be utilized for the drilling operation all year round.

This paper describes the basic features of a jackup type mobile drill rig platform for operation in a water depth of 500 ft. in the Gulf of Mexico during the hurricane season (about 550 ft. in the non-hurricane season). Included are drawings showing the general configuration of the unit and the method for jacking up and jacking down, as well as estimates of weight and cost.

The jack-up drill rig is compared with a semisubmersible as are presently required for drilling in water depths ranging from 450 to 600 ft. As part of this comparison, information is furnished relating to jack-up drill rigs callable of operating in water depths of 450 to 600 ft. in the Gulf of Mexico and the North Sea.

INTRODUCTION

The trend in offshore exploration clearly indicates that the oil industry has a need to search for oil and gas where water depths are 300 to 600 ft. and beyond the capability of the present jack-Up drill rig platforms. Further, for these water depths there is a need for a stable platform from which drilling can proceed under all types of weather conditions except for the most severe storm.

It is for this reason that the authors' company, George G. Sharp, Inc., developed the design for the jack-up type mobile drill rig platform described in this paper.

CONCEPT

General

The jack-up type mobile drill rig platform described herein for operation in a water depth of 500 ft. in the Gulf of Mexico during the hurricane season is based on calculations and drawings developed by the authors' company. The design has been developed to conform to the requirements of the American Bureau of Shipping"Rules For Building and Classing Offshore Mobile Drilling Units". Although the unit described is configured for operation in the Gulf in a water depth of 550 ft during the non-hurricane season, minor design changes will permit operating in greater water depths.

The materials selected will permit operation of the unit in the North Sea, but due to the more severe weather conditions in this area, the unit as presently configured would be confined to a water depth of around 460 ft. during the winter season and a somewhat greater depth when the weather conditions are not as severe.
Calculation of Long Term Values for Motions and structural Response of Mobile Drilling Rigs
Authors: Pedersen Bjørn , Egeland Olav , Langfeldt Jan N.
Published: October 2008

A method is presented which is based on statistical evaluation of loads and corresponding stresses in irregular seas. Observed wave data in the potential areas of operation are used as a basis for simulating characteristic sea states on the computer, i.e. the time variation of the irregular wave pattern. On this basis the maximum stresses over the lifetime of the structure are predicted.

I INTRODUCTION

The most commonly used method for evaluating wave loads on an offshore structure has until now been to base the calculations on one or more design waves. This was also the case in the shipbuilding industry some years ago. When ship size increased, however, it became obvious that the design wave method led to unreasonable results in many cases. It was realized that the random nature of the ocean waves, and consequently of the responses of a structure to these waves, could only be described by statistical methods.

Recent research had revealed that the irregular wave pattern could be described by linearly superimposing regular waves of different frequencies. In this way it was made possible to take into account all the wave components present in a realistic sea. The development of methods for calculating the response of a floating structure to the regular waves was also initiated in this period. Det norske Veritas has played its part in this development and a number of computer programs relating to ship problems have been the result, see for instance /1, 2/. Calculations for ships based on the principles indicated have proved successful and these methods are now commonly used.

It was a natural step to try to extend the same principles and methods to offshore structures like drilling platforms.

The following will give a description of these methods as applied to semisubmersibles. Fig. 1.1 illustrates the procedure in principle. A particular feature is that the wave load program is directly connected to the stress analysis programs.

2 HYDRODYNAMICS

2.1 Equations of motion

The following forces acting on the platform are accounted for in the present analysis:–Hydrodynamic forces due to the relative motion between platform and waves–Inertia forces due to platform Motion–Restoring forces set up by the Anchors–Hydrostatic forces and other static forces applied at any point and acting in. arbitrary direction, e.g. wind and current forces.

The static forces are included in the list for completeness only, of course they do not influence the dynamics of-the problem.

The set of equations used to solve the motion problem in six degrees of freedom may be written in matrix notation as:(Mathematical equation available in full paper)

where M, Band C are six by six symmetric matrices. M is associated with the platform mass and added mass, B with the damping, and C with restoring. The displacement matrix may be written more explicitly as:(Mathematical equation available in full paper)
The First Dual Lateral Well Successfully Drilled Underbalanced in Libya
Authors: Safar Hussein , Azhary Sadek , Hijazi Ahmad , Qutob Hani , Chopty James , Pham Chau
Published: October 2008

The B24 well in the Fidaa Field was the first dual lateral underbalanced horizontal well drilled in Libya and the second well of Zueitina Oil Company's (ZOC) underbalanced drilling campaign.

The targeted reservoir "Facha" is partly depleted after 23 years of production to a 7.2 ppg equivalent mud weight. Nitrified diesel, a two-phase drilling fluid, was used to drill the reservoir section of the B24 underbalanced to avoid circulation losses and formation damage. Real time LWD was crucial for geosteering the well path in a complex reservoir structure and real time annular pressure measurement was also necessary to ensure the underbalanced condition was maintained throughout the entire UBD drilling phase.

Two 6" horizontal drains were drilled successfully with 2053' and 1517' drain lengths. Integrated efforts of ZOC and service companies of various disciplines during planning and operation stages of the well led to the success of the project. No QHSE incidents were reported and the productivity of the well was enhanced significantly.

The B24 well's production alone contributes to over 30% of the total Fidaa field production.

Introduction

The Fidaa field in the north of Muelah Graben at the western edge of Sirt Basin was discovered in 1979. The structural map of the Facha reservoir (Figure 1) shows the structure to be northwest - southeast trending with approximately 9.5 by 2.5 km size and a pay zone thickness of 28 feet. A total of 23 vertical wells were drilled to date in the Fidaa field. Well B24 was the last one drilled horizontally with two lateral legs. It was completed in May 2005.

Facha reservoir "C" layer is dolomite with vuggy porosity of 23% on average and logs indicate extensive fracturing. The reservoir pressure of the upper Facha ranges between 1600 psi to 2330 psi and the average pressure along the planned drain hole in the Facha "C" was 1900 psi at 6085' TVD (6 ppg EMW). The Facha reservoir is an oil bearing pay zone with a stock tank oil gravity of 41.7° API, a gas oil ratio of 68 SCF/STB, and water cut ranging from 6% to 70%. Due to a partially depleted pressure of the Fidaa field, lost circulation and other drilling problems were encountered in the field.

Challenging Problems

To cover the un-drained areas of the field, drilling new wells with conventional drilling fluids was very difficult. Severe losses and differential sticking especially in the horizontal reservoir section(s) were experienced. The invasion of foreign fluids and cuttings into the reservoir led to formation damage that accounted for low flow rates after the wells were put into production. Therfore, another drilling methods or techniques were needed to be considered by Zueitina Oil Company to solve the problems of the Fidaa field.

Solution

The Drilling Engineering Department of Zueitina Oil Company investigated many possible alternatives to solve the problems encountered which could also be applied economically and effectively in the field.
Ormen Lange-Challenges in Offshore Project Execution
Authors: Nordvik Birgitte , Kilde Einar
Published: October 2008

Ormen Lange is the second-largest Norwegian gas field and was discovered by Hydro in 1997. The Ormen Lange field comprises an offshore subsea solution approximately 125 km off the west coast of Norway, an onshore gas processing and export facility at Nyhamna, a gas export transportation system between Norway and the UK, and the Easington gas reception terminal in the UK. The Ormen Lange development is divided into three main sub-projects: Onshore, Offshore, and Langeled.

This paper gives a summary of the Ormen Lange Offshore development, including descriptions of project execution and contract strategy, and how Hydro's competence and systematic work processes have been utilized in order to secure efficient progress. The Offshore project will be further described - including the technical challenges of the project -in three OTC 2007 papers:OTC 18965 Ormen Lange subsea production systemOTC 18967 Ormen Lange pipelines installation and seabed preparationOTC 18969 Ormen Lange subsea compression pilot as a supplement to the summary provided here.

Introduction

Ormen Lange is Norway's second largest gas field, with expected gas export equivalent to the total energy demand in Norway.

The Ormen Lange gas field was proven by drilling in 1997, and Hydro was selected as operator for the development of the field in December 1999.

After an intensive period of studies, Hydro decided in 2003 to develop the field without any platforms. The subsea solutions on Ormen Lange will take the technological developments on the Norwegian continental shelf a significant step forward.

Project Description

The Ormen Lange development is an innovative subsea to shore concept, comprising 24 large bore wells drilled from four subsea templates, with the following key challenges:Extreme seabed topographyMain production area located in an avalanche / slide areaLow temperatures, minus 1°C at seabedStrong currents, waves and winds850 -1,000 m water depthHigh flow production wells 10MSm3/d

The two first subsea production stations will be located 120km from shore, at a water depth of 850 m. Each of the subsea production stations weighs more than one thousand tonnes, and will produce 80 MSm3/day from large bore wells. The stations will be remotely controlled from the shore.

From the subsea production stations, two 30? pipelines will transport the well stream to the onshore plant for processing. The pipelines are laid across an extremely irregular seabed, with boulders and slide blocks up to 60 m tall in the Storegga slide area. Furthermore, the pipelines cross the slide at an inclination of up to 40 degrees. The Storegga slide created a tsunami 8100 years ago which hit the west coast of Norway and the coasts of the UK. NOK 700 million has been spent to make sure that the slide area is stable, and that development and gas production will not change its stability. In order to make the pipeline concept feasible we have drawn on all relevant expertise worldwide, and stretched the technology to its limits.
On Fatigue Design Rules For Welded Structures
Authors: Gurney T.R. , Hicks J.G.
Published: October 2008

A comparison between the design rules in use in various countries has shown that there is a wide difference between them on such questions as design stresses, the treatment of high tensile steel vis-a-vis mild steel, the question of whether or not a cumulative damage approach should be used in design and on what factors of safety should be adopted. However, published test data exist for many types of detail and the paper quotes the results of a statistical analysis of these data which could form the basis for a universal set of ‘master rules’. It is suggested that all design standards should be related to the same basic data. In the context of offshore structures much additional data are required, particularly reliable information about the fatigue strength of tubular joints and about corrosion fatigue.

INTRODUCTION

Offshore structures, whether they be floating or fixed platforms, are subjected to loading of an extremely complex nature arising from a variety of sources, but particularly from wave action. The severity, both in terms of magnitude and frequency of application, of these loads varies considerably from one part of the world to another, but in some places at least it can be such that the fatigue strength of these structures has to be treated as a most important design criterion. Thus, in the North Sea several structures are known to have suffered fatigue cracking, sometimes of major proportions and after only a relatively short period in service. In contrast, there is reputed to be no fatigue problem in the Gulf of Mexico.(1) The difference stems from the much more, severe fatigue loading spectrum in the North Sea.

In view of the current, and future, large investment in offshore structures and equipment, and the potential cost in terms of lost production, environmental pollution and new capital requirements, which could result from major structural failures, it is pertinent to consider what steps can be taken to reduce the risk of fatigue failure to acceptable levels. Clearly, there is a need for a realistic set of design rules which can readily be interpreted by designers.

In the context of offshore structures, fatigue can be taken to mean high cycle fatigue. It is the purpose of this paper to review the current situation regarding high cycle fatigue design rules for welded structures, to suggest ways in which improvements could be made and to point out regions where further research seems to be necessary.

EXISTING RULES AND THEIR BASIS

Historically, the majority of the design standards relating to high cycle fatigue have been concerned primarily with bridges, and particularly railway bridges.
Characterization of Near Seabed Surface Sediment
Authors: Low Han Eng , Randolph Mark Felton , Rutherford Cassandra , Bernard Bernie B. , Brooks James M.
Published: October 2008

Accurate measurement of the shear strength profile in the upper 1 m of soft sediments is crucial for pipeline and riser design, particularly for deep water developments. In this paper, some existing approaches for the strength characterization of seabed surficial sediments are reviewed and the conclusion reached that performing in-situ strength tests within box core samples is the most reliable means of characterizing the shear strength of soft surficial sediments. A box corer for recovering high quality undisturbed sample of the very soft seabed surficial sediments (upper 0.5 m of the seabed) and a new manually operated penetrometer (DMS) for measuring profiles of undisturbed and remoulded undrained shear strength within the box core sample are described. Field data for DMS tests in box cores recovered from a site in the Gulf of Mexico are presented and compared with the strength data measured by motorized miniature vane tests to evaluate the potential of the DMS in characterizing the shear strength of seabed surficial sediments. These data showed that performing DMS tests in box core sample can provide a reliable and time effective means of obtaining strength profiles (undisturbed and remoulded) of soft seabed surficial sediments.

Introduction

Accurate characterization of seabed surficial sediments has became increasingly important due to escalating hydrocarbon field developments in water depths that are now approaching 3000 m, for which the cost of in-field flowlines and pipelines for exporting hydrocarbon products to shore forms a significant portion of the overall field development cost. However, the low strength of the surficial sediments, in the upper 0.5 to 1 m of the seabed, has rendered soil sampling and strength testing extremely difficult and has posed a major challenge in measuring the shear strength profile accurately, particularly in deep water. Typically, the shear strength of the seabed surficial sediments lies in the range 0 to 5 kPa, although in some deposits such as off the West African coast, a crust with strength of 10 to 15 kPa may be found (Borel et al. 2005; Ehler et al. 2005).

In this paper, some existing approaches for measuring the strength profile of seabed surficial sediment will first be reviewed. Subsequently, a box corer that is able to recover high quality undisturbed samples of the surficial sediments and a new manually operated penetrometer (DMS) for measuring undisturbed and remoulded undrained shear strength within the box cores will be described. Data from a field trial in the Gulf of Mexico will be presented, and compared with the strength data measured by motorized miniature vane shear tests, to evaluate the potential of the box corer and the DMS in the characterization of soft surficial sediments from deepwater sites.
Evaluation of PhaseWatcher Multiphase Flow Meter (MPFM) Performance in Sour Environments
Authors: Al-Khamis Mohammed Najim , Al Bassam: Abdulaziz Fahad , Bakhteyar Zaki , Aftab Muhammad Nadeem
Published: October 2008

Accurate oil, water and gas flow rate measurements from individual wells are essential in order to properly manage both the wells and reservoirs, as well as to obtain reliable data for production performance monitoring, optimization, allocation and simulation models1, 2, 3, 4, 5. Over the past three decades, there has been great advancement in the multiphase metering technology. These advancements have resulted in a significant improvement in measurement accuracy as well as in reducing the physical size of these meters which is a crucial element in limited-space environments as in offshore platforms.

The intent of this paper is to present results of a compact Multiphase Flow Meter (MPFM) " PhaseWatcher?? based on information gathered from Saudi Arabia, where more than one hundred meters have been installed so far in several fields covering wide ranges of fluid properties and operating conditions. Moreover, the paper will discuss in detail the effect of crude sourness (H2S concentration) and pressure on the meter's measurement accuracy.

Multiphase Flow Meter (MPFM) Design

The PhaseWatcher is designed to measure the total volumetric flow rates of oil, water and gas at line conditions. These flow rates are converted to standard onditions via a pressure-volume-temperature (PVT) package, which can be either the default Black Oil Model or a specific model derived using a client supplied PVT data.

The meter comprises of five basic components, Fig. 1:A Venturi meter with pressure transducers across it to measure the differential pressure between the inlet and throat of the Venturi.A nuclear dual energy fraction meter consisting of a Smart Detector and Barium Source, measures the count range of photons transmitted from the source to the detector at two different photon energy levels (the high energy level is used to measure the density of the mixture, while the low energy level is used to calculate the water-oil ratio).Process fluid temperature transducers, which measure the fluid temperature upstream of the Venturi section and the ambient temperature.A Blind Tee Static Mixer, used to homogenize the flow stream ahead of the Venturi meter.A process flow computer used to manipulate the measured data.
Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency With Nozzle Based Inflow Control Devices (ICD) in Sandstone and Carbonate Reservoirs
Authors: Raffn Anne Gerd , Zeybek Murat , Moen Terje , Lauritzen Jon Eric , Sunbul Ahmed Hassan , Hembling Drew E. , Majdpour Abdi
Published: October 2008

This paper discusses the PLT-correlated results of two test wells completed during 2006; one in sandstone and one in a carbonate reservoir, with the new completion technology of nozzle-based passive inflow control devices (ICD) which improves performance of wells with reservoir challenges as described:In highly productive sandstone reservoirs, horizontal wells suffer from uneven flow profile and subsequent premature cresting/coning effects. In general, there is a tendency to produce more at the heel than at the toe of horizontal wells, which contributes to poor well cleanup at the toe. Additionally, excessively increasing the rate and/or horizontal well length can increase the risk of limiting sweep efficiency, resulting in bypassed reserves1.In carbonate reservoirs, permeability variations and fractures can cause uneven inflow profile and accelerate water and gas breakthroughs. Wells with early gas or water breakthrough have to be shut-in until remedial plans are decided and implemented, resulting in deferred production.

The main reservoir objectives for applying passive ICD technology in the two test wells are:Sandstone: Decrease the influence of heel-toe effects and high permeability zones; hereby deferring water/gas breakthrough, improving well cleanup and sweep efficiency.Carbonate: Control flow rates from high permeability intervals and to limit production from each compartment based on lateral offset from the gas-oil contact to prevent premature gas breakthrough.

The test well PLT-logs were correlated to static reservoir simulations. Analyses of the well performances show that the objectives of both completions were achieved. By having proper matches of the completions with ICD, the value over standard completions can be evaluated.

Post-evaluation of the completion designs based on the PLT-log results has increased our understanding of the nozzle-based ICD performance. As a result several approaches for completing wells in both sandstone and carbonate reservoirs with ICD have been recommended in order to achieve optimized inflow performance.

Introduction

Two trial wells with nozzle-based passive ICD systems were designed and completed in 2006; one for sandstone and one for carbonate reservoirs. To evaluate and approve the new ICD completion, these wells were production logged and the results were carefully analyzed.

The most important feature of the ICD completion is the self-adjusting effect of flow variations anywhere along the well trajectory and whenever they occur during entire well life. The key benefits are:Increased well life and reserves due to improved sweep efficiency.Delayed gas and water breakthrough.Decreased water/gas rates after breakthrough when water/gas mobility is higher than oil.Improved well cleanup.
Small Field Development and Subsea Tieback Technologies
Authors: Hawkins David W. , Chipman Wayne Ivan , Dillabough Graham D. , Ruelokke Max , Way Fred
Published: October 2008

Twenty-four oil and/or gas discoveries have been made offshore Newfoundland and Labrador. Three of the oil discoveries have been developed and a fourth is under consideration. The focus of development activity has been on the larger oil discoveries. As production from the larger discoveries matures, facilities and other infrastructure will become available for development of the remaining smaller discoveries. Development and tie-in of smaller pools and fields provides an opportunity to utilize this spare production capacity at these fields. Currently, there are several satellite tie-in and expansion projects in progress and others are under review. Development of the discovered smaller fields will play an important part in sustaining production from offshore Newfoundland and Labrador. In addition, many of the offshore basins are under explored and represent other opportunities to supply the next round of developments.

Introduction

Newfoundland and Labrador, Canada's easterly province (Fig. 1) is strategically positioned on international shipping lanes, with unique access to global petroleum markets.
Arthit Field Development: Float-over Hardware Design and Issues
Authors: Tan Boon-Sze , Sahasrabudhe Sanjay , Haney James Allan , Leow Bee-Lay
Published: October 2008

The 17,500 metric ton Arthit PP topsides was successfully installed in December of 2007 in the Gulf of Thailand after a short voyage from Batam Island, Indonesia, where the topsides was fabricated. The topsides was installed in one piece using the float-over method. Three types of hardware components were designed and fabricated to facilitate the float-over. One type supported the topsides during the loadout, transport and float-over. The second type provided the interface between the topsides legs and the jacket. The third type was mounted on the pile tops and provided landing receivers for the topsides legs and final leveling and joining features. The design, fabrication, and operation of these three components will be discussed in this paper.

The float-over hardware components are designed to suit the " loose slot method?? of topsides float-over installation and rapid ballasting system of the transport barge. Arthit PP topsides float-over experience shows that float-over hardware components can be designed and implemented for offshore installation of large topsides.

Introduction

The installation of single piece, large-sized topsides by float-over method is a cost effective alternative since it minimizes offshore hook-up and commissioning. Various float-over methods and associated challenges are described in paper OTC 19072 by Seji and de Groot (2007). Installation of large topsides tends to produce large mating forces and relative displacements; thus placing high design requirements on sub-structure and topsides. A means of facilitating rapid separation of transportation vessel from underside of the topsides was vital for a successful float-over. The float-over hardware is essentially provided to reduce mating forces, accommodate large relative displacements, provide effective cone capture mechanism, and facilitate rapid separation of transport vessel and topsides.

During recent float-over installation of Arthit topsides, the transport barge was not guided by bumpers mounted on the jacket during the barge entry and exit from the jacket " slot??, or during the actual float-over operation. The mean position of the barge was controlled by a primary mooring system fixed to the sea floor plus a tug during entry and exit. In the float-over position a secondary mooring system of soft lines was designed to connect the barge to the jacket. The barge orbited in the slot without touching the jacket. This float-over concept is called the " loose slot method?? and is described in paper OTC 19230 by Kocaman and Kim (2008). This concept is the preferred method at J. Ray McDermott (J. Ray) since it minimizes barge contact with the jacket during slot entry and exit.

A rapid ballasting system was installed in the transport barge Inermac 650 during a dry-dock. The system is designed to separate the barge from the topsides in less than twenty minutes (OTC 19231, Kim et al, 2008). The rapidity of the ballasting reduces risk level during the float-over operation.
A General Method for Subsurface CO2 Storage Capacity Calculations
Authors: van der Meer Lubertus , Egberts P.J.P.
Published: October 2008

It is neither straightforward nor simple to estimate the capacity of a geological formation to store CO2. In a recent attempt to list the various estimates of CO2 storage capacity for the world and regions of the world (Bradshaw et al., 2006), the estimates are often merely given as " very large??, with ranges in the order of 100s to 10,000s Gt CO2. It is clear that there is a general lack of definitions, rules and general procedures for calculating storage potentials.

Having conducted studies in the past, TNO is convinced that we now need a more uniform and standard method to calculate the storage potential of any subsurface location - be it a gas or oil field (whether totally or partially depleted) or an aquifer. In any calculation of storage capacity, TNO prefers to include the concept of total affected space i.e. the entire space whose state or qualities change during the total storage time as a result of the storage operation. Furthermore, in the storage calculations we consider the injectivity of the selected injection location, and the pressure and fluid conductivity of the total affected storage space.. The intended free CO2 storage location must have enough storage space or enough sealing capacity to contain the CO2 for at least 10,000 years and prevent it from migrating to the surface. And finally, it must be taken into account that as a result of gravity segregation, the heavier CO2-saturated formation water will sink to deeper parts of the affected space.

We describe a standard method we have devised to be used for any storage location to calculate the maximum storage volume based on affected space and maximum pressurization, the storage potential based on injectivity, and finally the storage efficiency of the geological trap.

Introduction

We often need to know how much CO2 we can store in a certain underground space, or how much such space we need to store a given amount of CO2. In a recent attempt (Bradshaw et al., 2006) to list various regional and global estimates of CO2 storage capacity (figure 1), the estimates reported are often quoted as " very large?? with ranges in the order of 100 to 10,000 Gt of CO2. From the publications Bradshaw and his colleagues consulted it is clear that there is a lack of definitions, rules and general procedures for calculating storage potentials. The calculations of CO2 storage capacity are mainly based either on the solubility potential (Bachu et al., 2003) and ignore volumetric consequences and the kinetics of this process, or on a fixed percentage of a subsurface volume (Koide et al., 1992). None of the cases using the latter approach include any definitions. In this paper we will specify a method to calculate the Theoretical Maximum Storage Capacity. We will give comprehensive definitions of all the important parameters in a separate and upcoming publication. In the present paper, the parameters appear in italics. They are briefly described below.
Leak Detection in Subsea Pipeline: A Mechanistic Modeling Approach With Fixed Pressure Boundaries
Authors: Gajbhiye Rahul Narayanrao , Kam Seung Ihl
Published: October 2008

A subsea pipeline leak has caused a serious concern over the transportation of deepwater oil and gas production to onshore or shallow-water production facilities. Hazardous impact on marine environment and consequential economical loss resulting from the subsea pipeline leak became an important issue of oil and gas industries. Currently more than hundreds of hydrocarbon production projects are ongoing, and deepwater production is expected to almost double over the next decade in the Gulf of Mexico. Active development of deepwater activities in the Gulf of Mexico will undoubtedly lead to the expansion of subsea pipelines.

This study, for the first time, shows how a subsea pipeline leak can be modeled in a mechanistic way. Especially, a focus is made to the implication of fixed-pressure boundary conditions at both upstream and downstream locations, which is quite relevant to the way how the majority of field operations are actually operated and managed. The use of fixed-pressure boundary conditions leaves the change in inlet total flowrate (Dqtin) and the change in outlet total flowrate (Dqtout) as two possible leak detection indicators that can be monitored on real-time basis. The two-phase flow in subsea pipelines, which is filled with gas and oil mixtures, is analyzed using well-known Beggs and Brill's two phase correlations. The effect of different parameters on the mechanistic leak detection modeling is investigated accounting for gas compressibility, back pressure of the system, the pressure drop across the system, input fraction of gas and oil phases, and the fraction of gas and oil phases leaking out of the pipeline system through the leak.

The results exhibited the following outcomes:The leak could be more easily detected with increasing leak size no matter which of the two leak indicators (Dqtin or Dqtout) were used;The presence of compressible fluid in the pipeline amplified the disturbance to the system in general. This made the use of Dqtout less promising (but the use of Dqtin more promising at the same time) for leak detection;The loss of larger fraction of less dense and less viscous fluid through the leak caused the use of Dqtin less viable but the use of Dqtout more viable; andCombination of larger pressure drop across the system (i.e., the difference between the inlet and outlet pressures) and larger gas fraction at the leak (fgleak) made the use of Dqtout more favorable.

It should be noted that the net effect of the presence of gas phase, by taking gas compressibility, viscosity and density all together into consideration (i.e, (2) and (3) above), was a decrease in ?qtin and an increase in ?qtout. This means that the presence of gas phase in the subsea pipelines makes the use of qtout more reliable (but the use of qtin less reliable) as a leak detection indicator.
Comparisons of Various Fairing Geometries for Vortex Suppression at High Reynolds Numbers
Authors: Allen Donald Wayne , Henning Dean
Published: October 2008

Several fairing geometries have been tested with a tow carriage to examine their ability to suppress vortex-induced vibration and reduce drag. The tests were performed in the critical and supercritical Reynolds number ranges with fairing chord-to-thickness ratios ranging from 1.33 to 2.52. Stabilizer fins were attached to some of the fairings, while others had a thin tail or came to a point at the tail. All the fairings were allowed to fill with water and were free to weathervane while towed in a horizontal configuration on a flexible pipe. The results illustrate that larger chord-to-thickness ratio fairings provide lower drag than smaller chord-to-thickness ratio fairings. Smaller chord-to-thickness ratio fairings are most effective when the tail is thin and longer chord-to-thickness ratio fairings can benefit from the presence of a stabilizer fin.

Introduction

Fairings have been used by the offshore oil and gas industry to reduce vortex-induced vibration (VIV) since the late 1970s (see Every and King 1980; Gardner and Cole 1982; and Grant and Patterson 1977). Most early designs had fairly large chord-to-thickness ratios, and their use focused on drilling riser applications. The common wisdom was that fairings were unsuitable for production applications, due to the potential for marine growth to lock them in place or prevent them from weathervaning properly with the direction of the ocean current.

In the late 1980s and early 1990s, the authors, while conducting tests in a current tank, discovered that short fairings can be very effective at suppressing VIV. In subsequent testing over the next several years, the authors discovered that these short fairings were also effective at critical and supercritical Reynolds numbers (Allen and Henning 2003). This short fairing geometry was subsequently used for several deepwater production risers as well as several drilling risers. Most research and development over the next few years was focused on designing this fairing properly to insure its performance, fitness for purpose, and integrity. While development work was done to expand its usefulness to a wide range of tubular installation methods, very little research was performed to produce new fairing shapes that can effectively reduce both VIV and drag.

The objective of this set of experiments was to ascertain the effects of various fundamental geometrical features of fairings on their performance, as measured by vibration and drag reduction. While a systematic approach was desired, it was recognized that a large number of parameters could be varied. These included:The chord-to-thickness ratio;The chord-to-diameter ratio;The presence of a fairing nose and its shape;The shape of the tail (pointed or flat with varying possible widths);The curvature of the two sides of the fairing;The presence of a stabilizer fin;The geometry of the stabilizer fin.