bluuebunny/crossref_metadata_2025 huggingface dataset:
Wireline Well Tractor: Case Histories
Authors: Hallundbæk Jørgen , Østvang Knut , Haukvik John , Butler P. , Skeie Terje
Published: October 2008

The wireline Well Tractor has in the North Sea area completed various wireline jobs in horizontal and extended reach deviated wells. The electric driven Well Tractor has made it possible to perform wireline operations in horizontal and deviated wells such as PLT jobs with surface read out, running of perforation guns, running of specialized tools, setting and pulling of plugs etc. Since March 1996 the Well Tractor has run numerous jobs on Statoils platforms in the North Sea and also jobs for other major oil companies in the North Sea area and North America. This paper describes the implementation of the Well Tractor technology. Logging, plug setting, perforating operations and fishing in wells with a horizontal section of more than 1600 meters are included in the case histories.

Introduction

The number of horizontal and extended reach wells worldwide is dramatically increasing. It is possible to drill and complete ERD, long horizontal and designer wells with no greater difficulty. However, when a requirement for intervention in these type of wells occurs and in particular for live well intervention, coiled tubing or snubbing operations have up to now been the only options. In many cases and particularly in wells with high well head pressure coiled tubing and snubbing operations are impractical and involve a large amount of costly equipment, personnel and rig time. Logistical problems, in particular for coiled tubing operations are evident, especially for ERD type wells as the coiled tubing reel weight often exceeds the platform crane capacity.

The costs for these horizontal and deviated well intervention operations with coiled tubing or snubbing are excessive and in many cases operations such as production logging is simply not performed because of the costs involved.

Development Phase

Statoil has for the past three years focused on a strategy for reducing intervention costs. As a consequence of this Statoil decided to support and play an active role in the development, testing and implementation of a downhole tractor. Statoil as the head sponsor and Maritime Well Service as the co participating service company supported the development and manufacturing company Welltec. The co-operation and joint efforts of the three companies is the obvious reason for the success of the wireline Well Tractor project.

Economical analyses performed in Statoil have revealed considerable cost savings when utilizing wireline tractors for electric line type operations vs. coiled tubing for the same type of operations. Further, it is expected that the market for production logging in ERD- and horizontal wells will increase due to the reduced intervention costs.
Development, Testing, and Field Case Histories of Multilateral Well Completion Systems
Authors: Longbottom J.R. , Dale Dana , Bruha Scott , Waddell Kevin
Published: October 2008

Multilateral oil and gas well concepts have been in existence since the early 1900's, but advances in directional and horizontal drilling have recently made this reservoir development approach more feasible. Although numerous multilateral wells have been drilled, particularly in the Austin Chalk, until now completion methods have been limited in providing features to manage borehole stability, flow control, and well maintenance.

This paper will discuss several examples of the advances in drilling technology that have made these multilateral well development strategies possible. Information will also be provided on several simple multilateral well completion techniques as well as a multilateral system that will 1) mechanically connect the lateral liner to the parent casing, 2) allow through tubing re-entry access to selected laterals, and 3) seal the junction between the lateral and parent bore so that flow control capability can be maintained. In the latest system developed, the hole size of the lateral has been maximized in comparison to the parent wellbore casing, and full bore access to the lateral liner drift ID without restriction has been provided. Information will be presented concerning the project methods undertaken to develop this system, the bench tests that were performed for the components of the system and results of the full scale system test conducted. An "integrated development" approach with a multidisciplinarydesign team and direct producing company involvement was used in the development of the full featured multilateral completion system and proved to be an instrumental factor in the achievement of its success. In addition to information concerning application of multi-lateral completion techniques to new completions, the concept, as it has recently been applied toa recompletion, will also be discussed.

Case histories of the completion experiences of two wells in which the system has been successfully implemented as well as several earlier successful completions using other systems will be presented. In addition, details will be provided concerning the case history in which the technology was employed in a mature field. Experiences to date have shown that multilateral technology can provide technical and economic feasibility for both new installations and recompletions.

Introduction

Many enhancements have recently been made to multilateral completion systems, not only as a result of advances in technology but also because of changes in developmental concepts that have been instrumental in achieving many of the system successes. A primary factor in the increased interest in multilateral completion technology has been its enhancing impact on the economics of field development.
Steady-state and Transient Thermal Performance of Subsea Hardware
Authors: Zabaras George J. , Zhang Jianfeng
Published: October 2008

The thermal performance of subsea hardware is of ultimate importance to the economic development and reliable operation of deepwater subsea oil and gas systems due to the potential for hydrate formation. Results of numerical calculations are presented on the thermal performance of subsea equipment such as wellheads, tubing and flowline jumpers and flowline field joints. In contrast to previous published studies on the thermal performance of insulated subsea wellbores and flowlines, the currenr. study addresses the thermal performance of the subsea equipment that can provide weak thermal links for the subsea system.

While subsea insulated flowlines can eliminate or reduce the risk of hydrate formation during steady-state production, they may not provide sufficient cooldown time before hydrates are formed during an emergency shutdown. Subsea wellheads, pipe field joints, manifold and flowline tubing jumpers are very difficult to insulate effectively. As a result, these pieces of equipment exhibit faster cooldown to hydrate formation temperature than either the wellbore or the flowline.

A two-dimensional general purpose finite-element partial differential equation solver was utilized to analyze the steady state and transient thermal behavior at different cross-sections of the subsea tree. In contrast to the intuitive common belief that a subsea tree cool down time to hydrate formation temperature is of the order of several hours. a cool down time less than two hours was determined after a system shutdown. Steady-state analysis of a flowline field jo nt indicates that the joint degrades the flowline thermal performance causing up to a 20%) increase in the flowline overall heat transfer coefficient. To our knowledge. such results have not yet been presented in the literature.

Introduction

Significant opportunities exist to employ subsea methods in the development of oil and gas fields in deepwater environments. Subsea methods are proving to be not only safe and reliable but often the most cost effective development option.

Subsea system design is driven by many factors such as produced fluid phase behavior and multiphase flow characteristics in flowlines and wellbores, as well as our ability to reliably predict the fluid behavior and the equipment performance over the range of conditions to be encountered during the produce life of the field. While all these factors are very important, the behavior of the reservoir fluids is a key element in the successful design and operation of a subsea system.

The potential for hydrate formation in a produced reservoir stream is perhaps the greatest challenge in any deepwater development in the Gulf of Mexico and elsewhere. Significant design effort and cost for subsea systems is directed toward mitigating the risk of plugging the system with hydrates1 and paraffins/ asphaltenes2,3.
Wet Gas Multi-Phase Measurement
Authors: Tuss Bernie
Published: October 2008

In the last decade, the world of petroleum industry multiphase measurement has evolved from its infancy in research to operational equipment. Virtually all the endeavors were focused on the predominantly liquids aspect of multi-phase, mainly in the low GOR, low water cut regimes. With considerable time and money spent on development, the technology has evolved to cover both water and oil-continuous flows of 0-100% water and to GVF (Gas Volume Fractions) upwards of 90%.

With the advancement of technology and the increase in natural gas usage, the demand for "wet gas" metering has become more apparent. Wet gas is roughly defined as production or pipeline streams with GVFs above 95% gas at the point of measurement.

This paper presents a discussion of the equipment currently available and/or in development and the efforts put forth to perform this type of multi-flow measurement.

Background

Measurement of gas well production has been primarily left to the orifice plate, recognizing that the resulting flow calculations were in error because of the associated liquids (water and condensate). Several attempts have been made (with little or no success) to quantify the degree of error in orifice plate measurement with variouspercentages of liquids.

Well testing of gas well production is predominantly accomplished by two or three phase well test separators, often with little concern for testing of liquid carryover in the gas, entrained and solution gas in the liquids, water carryover in the oil, and oil carryover in the water. Wells that surge or have slugging flow patterns often flood normally sized (for average flow) test separators, because the average liquid flow is considerably less than the liquidslug flow rates. Likewise, a well may tend to produce considerably more water as the well ages, and the test separator, by its internal design, is incapable of handling to 10 times the usual amount of water that can be experienced from one well test sequence to another. The range ability of a well test vessel and/or separator level control system is difficult to change in the field. A better, less expensive, lighter weight, portable and more accurate "mouse trap" was needed.

Wet Gas Technology

Virtually any and all multi-phase measurement technology has its limitations within different flow regimes. Considerable use is made of combining several technologies into a given high gas fraction (wet gas) multi-phase meter. Those technologies include:Phase DiversionCross CorrelationSplit PhaseUltrasonic

In addition to the existing or near operational technologies in wet gas metering additional approaches, such as nuclear activation, polymer solubility, and radioactive isotopes, are in the research and design phases in both Europe and the United States.
Factors Affecting Shut-In Pressure Rise: Kicks in Offshore HPHT Wells
Authors: Schilhab Larry C. , Rezmer I.M.
Published: October 2008

Deep water and HPHT operations are two areas where the use of sophisticated simulators can enable difficult processes and procedures to be broken down into individual identifiable contributions. In this paper we discuss some of the factors that are likely to affect shut-in pressure rise in offshore drilling operations, and how a simulator can be used toanswer other, less obvious questions concerning deep water well control operations.

We examine the effect of gas solubility by considering a gas-kick in a deep HPHT well drilled with oil-base mud. In this case, most of the influx will be dissolved in the mud, thus removing one of the processes for increasing the wellbore pressure. In terms of a safe state to disconnect from a well in rough weather, provided that the mud yield stress negates migration of the gas-cut mud, leaving the influx in solution at the bottom of the well should not lead to increasing wellbore pressures.

Significant wellbore pressure effects may also occur after closing the blowout preventers (BOP'S) on a well without an influx (or with an influx in solution), and allowing the mud to heat up. We show that in typical HPHT geometries the pressure can rise by up to 8 bar/°C. Similar magnitudes of pressure can also increase whilst circulating trapped gas out of a BOP at the end of a well control operation. We note that these effects may also be attenuated by fluid loss and wellbore compliance for wells with significant openhole sections.

Indeed, gas trapped in the BOP should be safely removed by established well control procedures. However, preliminary studies with the simulator (and confirmed by field tests in the literature) have shown that an accidental release of a small amount of gas into a deep Water riser may disperse, and not cause the riser to unload.

Introduction

The oil industry has had success in overcoming many of the technological challenges posed by drilling in deep waters and in high pressure, high temperature regimes.

Recently there has been discussion concerning the determination and determination of shut-in pressure build-up. There have been many cases of surface pressures taking a long time to stabilise. The reasons for this can be one, some, or all of the following:The influx originated from a low permeability zone.The influx created an instability in the wellbore leading to hole sloughing and packing off.The influx is migrating.The influx has dispersed.The influx is going into solution.Fluid is leaking off from the wellbore.The openhole section/casing is compliant.There are significant temperature effects.

Clearly, there are many factors that can modify the nature of the initial build-up and the stabilising of the shut-in pressures. In we consider in turn each of the processes and parameters that affect the shut-in pressures, and the estimate of the rate of gas migration.
From The Tpg 500, A Production Drilling Quarter Jack-Up To The TPG 3300, A Semi-Submersible Platform For Deep Water
Authors: Thomas Pierre Armand
Published: October 2008

This paper shall endeavour to present the now proven reliable and cost effective technological solutions developed by Technip-Geoproduction (TPG) for oil and gas field exploitation.

The first TPG 500 was successfully installed offshore in the U.K. sector of the North Sea in early 1996. This drilling, production and quarter jack-up capable of operating in North Sea conditions in up to 500 ft water depth, can be seated on either piled steel foundations or on a concrete storage base.

The drill floor may be located either directly over the moonpool, over a wellhead jacket in cantilever mode or over a wellhead jacket in skid-mode. A new platform design with drilling/production and accomodations facilities, the TPG 3300, has now been developed for fields located in very deep water (3300 A and below). The concept combines the main advantages of the deep draft semi-submersible during operations with the proven jack-up technology of the TFG 500 used for construction and installation. Its anchoring is a conventional catenary mooring system and its hydrodynamic behavior allows the use of dry wellheads.

Both platforms present common features. The surface wellhead trees are supported by the deck platform. They can be constructed onshore, at most fabrication yards because of their simplified l o a d d procedure. They can be wet towed or alternatively the TFG 500 may be barge transported. Their main assets are the self-installation of a fully quipped and pre-commissioned platform which meets the high safety requirements of fixed offshore structures. Major offshore hook-up and commissioning operations are therefore avoided.

At the end of the field life, the platforms may be self removed and transported to another site. The combination of all these advantages significantly reduces the capital and life-time costs.

INTRODUCTION

Following the success of the TFG 500, this jack-up was targeted for further development Techinp-Geoproduction has extended the range of platforms it offers the oil industry with the TFG 3300. The TPG 3300 is a deep draft semi-submersible platform with dry surface wellheads and catenary moorings, designed for the deep water field developments (3300 A water depth and below). Both versions are self-installing fully integrated platforms which combine all the functions usually found on fixed platforms : drilling, production facilities and accommodation. As implied by their similar names, these platforms have many common inherent features such as the construction method, easy transportation to the site, self-installation, and adaptability to differing environmental conditions. Their designs are targeted to fit small to large topside facilities with potentially a high number of wells being drilled from the central platform location.

DESCRIPTION OF THE PLATFORMS

The platform watertight deck supports all the equipment required for production, drilling facilities and accommodation. The rigid connection between the deck and the legs is ensured by the locking mechanisms.
An Integrated Team Approach to the Design, Construction, Start-Up and Operation of the World's Most Modern Drilling Rig.
Authors: Croucher T.M.
Published: October 2008

In 1994, Phillips Petroleum Company Norway, the operator of the Greater Ekofisk Area fields in the central North Sea, signed a contract for the construction of a state of the art, fit for purpose Drilling Rig to be located on the new Ekofisk 214 X wellhead production platform. The rig was an element of major importance to the Ekofisk II project, the redevelopment of one the largest fields in the North Sea. The start-up of drilling on the 214 X platform was the first major milestone in the Ekofisk II project and the timely redrilling of the Ekofisk field wells from the new rig was vital to maintain production levels. On 26th October 1996, exactly on schedule, the first well on the 214 X platform was spudded. To date six wells have been drilled by the rig including the fastest well ever drilled in the Ekofisk field. The drilling program is currently on schedule and the rig has operated at an average availability of 98%. The success of this project can be attributed to a number of factors, however, one element stands clearly as the key success factor - a truly integrated team approach to all phases of the delivery of the rig! From the very beginning, representatives of the real customer of the product, the offshore drilling team, joined the rig supplier's design team to work shoulder to shoulder on the specification and preliminary design of the rig. As the design process moved forward, the customer representation on the team was strengthened. Ultimately, the customer participated in an active manner in all aspects of design, construction, commissioning and start up of the rig. This paper will detail both the underlying philosophy and the practical process by which this state of the art rig was successfully built and put to work. The paper includes a description of the rig itself, a review of how the integrated team approached the various phases of delivery of the rig and an outline of how the project was managed. The paper then discusses the issue of whether an automated rig can lead to a reduction in manning levels and covers the unique way in which the rig crews rig were trained. Some equipment performance figures are included to demonstrate the successful operational capabilities of the rig, and finally some conclusions are drawn from the lessons that have been learned.

Introduction

The 214 X platform is part of a complex of facilities located at the centre of the Ekofisk field. Ekofisk is one of eight producing fields making up the Phillips Norway Group's Greater Ekofisk Area (production license 0 18) located in the southern comer of the Norwegian Sector of the North Sea. The Ekofisk field, discovered in 1969 and put on production in 1971, has recently entered into a new phase of redevelopment. Increasing operating costs, the result of ageing facilities and the need to mitigate the effect of seabed subsidence caused by reservoir compaction, has been the root cause of the redevelopment.
A Radical Alternative Approach To Design And Construction Of Pipelines In Deep Water
Authors: Palmer Andrew
Published: October 2008

The design of pipelines in deep water is conventionally governed by the external pressure. The line is laid air-filled, and the wall has to be strong enough to resist collapse and buckle propagation. This leads to extremely high wall thicknesses, often well over 1.5 inches (38.1 mm) even for modest diameters, to correspondingly high costs, and to additional difficulties with welding and possible repair. Newcomers to underwater pipeline engineering often ask why the pipe is always laid air-filled. This paper pursues that question, and explores the implications of laying the pipe partially liquid-filled, so that the external pressure is partly balanced by internal pressure. It presents the results of design and lay analysis for such a line. The pipe can then be much thinner and cheaper. It may be heavier, but overall it turns out to be less costly to lay a thinner pipe, even if the lay equipment has to be somewhat stronger. There are commissioning and operational implications if the line cannot be completely depressurised. These implications are much less serious for an oil or water line than for a gas line. The application is to economical design of large-diameter pipelines in deep water, such as the projected pipelines from Arabia to India and Pakistan. The results include graphs and formulas that can be used to design pipelines that will be laid partially water-filled. The most significant aspect of this radical alternative is that it offers a way forward which breaks free of a traditional constraint. The need for deep-water pipelines is clear. Some of the design and construction problems become easier in deep water, and some become more difficult. The principal difficulty is the inescapably large external pressure, which implies a large wall thickness if the pipeline is to be able to withstand the external pressure while it contains air at atmospheric pressure. A little can be done to lessen the problem by better understanding of collapse. A radical paradigm shift makes it possible to break free of the design constraint imposed by buckling.

Introduction

The future importance of deep-water production of oil and gas scarcely needs to be restated. Most of the oil and gas to be found in shallow water, in reasonably benign environments, and close to politically stable countries, has probably been found, and much of that is in the course of development. In the coming years the industry will be compelled to move into more demanding environments, into deeper water and into hostile environments such as the Arctic. In the recent Deep Offshore Technology conference in the Netherlands, Tim Warren said that "Deep water is the most significant opportunity facing Shell". Another major operator has estimated reserves in deep water off the continental shelf to be more than 40 Bbbl oil equivalent, of which 18 Bbbl are off West Africa and 8 Bbbl off Brazil. Pipelines will plainly be a major part of these new developments, and the cost of pipelines cannot be allowed to become a weak link that limits development.
Innovative Way to Run Liners in Horizontal or Extended Reach Wells
Authors: Fuller M.S. , Gharesi A. , Kaspersen B.
Published: October 2008

It has long been recognized that the ability to run a liner string to depth in highly deviated, horizontal or extended reach wells is limited by the amount of weight that can be applied from the surface to the liner string. Dog legs and horizontal sections create friction that reduces the amount of force that can be transferred to the liner to move the liner down hole. A new drilling fluid operated telescopic joint has been developed and tested that provides the additional "push" down hole to enable liners to be run where weight alone cannot provide the force necessary to install the liner. Through the use of a cyclical valve arrangement, the telescopic joint can be used to assist the liner through tight spots in the hole as well. Full circulation is provided to assist in removing cuttings if the liner is "drilled down" or establishing circulation for cementing of the liner. Designed to be a part of the liner running string, the telescopic joint provides hydraulically created forces for pushing liners or setting liner top packers. This provides cost savings by being able to locate a liner top exactly where needed regardless of hole deviation and direction. Further cost savings are expected in the reduced amount of weight needed to get the liner to bottom. This paper will describe the conventional liner running methods along with the improvements available with the telescopic joint.

Introduction:

As the oil/gas drilling industry continues to face new challenges, more sophisticated equipment is needed to allow the reserves to be retrieved. Using operations related to the installation of well bore liners as the background information, several different areas that historically provide new challenges are described and the potential solution discussed.

1. Installation of long liners in highly deviated or extended reach wells.

Figure 1 (available in full paper)

When installing long liners, especially in the long horizontal wells usually associated with extended reach drilling, problems may be encountered in reaching the desired depth due to high friction between the liner and the hole. Adding weight alone may not always solve the problem. The liner assembly is often rotated to help reduce the sliding friction. However, it is often observed that due to centralizers and scratchers on the liner itself, friction makes it difficult to rotate and still have enough. force to push the liner into the extended reach or horizontal section of the well. Centralizers are often removed to reduce the friction and allow the liner to reach the target. This results in potentially reducing the quality of the cement job. The purpose of the Telescopic Joint is to avoid these problems. The Telescopic Joint is added between the drill string and the liner's setting tool (See Figure 1). The weight of the drill string is used to anchor the Telescopic Joint, while the force generated in the Joint overcomes the friction between the hole and the liner and pushes the liner to the correct position.
Uncovering Peru's Offshore Petroleum Potential
Authors: Rivero F.  Zúñiga , Keeling J.A. , Roe H. Hay
Published: October 2008

TIlis paper attempts to spark a new phase in the exploration of Peru's 2,500-km-long continental shelf by helping to define major hydrocarbon possibilities in this extensive area. Recent seismic data acquired with optimwn field parameters have enabled us to define the tectonic, structural, and stratigraphic setting of Peru's coastal basins. Offshore Peru could well become one of the prominent oil and gas plays of the next decade.

TIle latest geophysical surveys, coupled with recently completed detailed geophysical and geological studies have confinned that:There are ten coastal sedimentary basins or sub-basins. Four of them are located entirely offshore while twoextend from onshore across the shelf to the upper continental slope and beyond.Most of the basins are strongly linear and parallel to the coast, in places bounded by one or two pre-Tertiary subsurface ridges-basement highs tllat show up clearly on seismic sections.Three basins that contain commercial oil or gas production all extend wlder the continental shelf.The total offshore area of tlle ten basins, out to a water depth of 2,000 m.. exceeds 150,000 sq. km. (37 million acres).Gross sedimentarythickness in the ten basins, as interpreted from modem seismic data and from drilling, ranges from 7,000 m to more than 20,000 m. This includes substantial thicknesses of previously unsuspected and prospective pre-Tertiary sediments, ranging in age from late Paleozoic to late Cretaceous.The most recent estimates of future hydrocarbon potential for the ten basins total 22 billion bbls of oil, without counting the onshore sectors of four basins. If natural gas were discovered, the equivalent potential would be 132 Tcf.

Offshore, almost no wildcatting has taken place south of the Talara basin., which has produced about 1.6 billion bbls of oil, including 280 million bbls from the shallow offshore sector, and over 3.5 Tcf of natural gas.

Introduction

Marine exploration off the Peruvian coast (Fig. I) has been going on intennittently since the 1960s, but it is only recently tllat a thorough, fresh look at Peru's entire offshore has revealed previously unsuspected potential. Rather than isolated basins with a relatively thin section of late Tertiary sediments1 we now know that a thick prospective sequence is present along the entire coast, in places exceeding 10,000 m total thickness.

Findings.

The latest extensive regional seismic survey (Table I) was recorded and processed in 1993–94. Under detailed review, substantial changes have been made in the preliminaryinterpretation. For example, a detailed study of interval velocity has shown values as low as 3,836 m1sec at a reflection time of 7.1 seconds, in water less than 200 m deep. We must conclude that continuous reflections previously thought to be intrabasement more likely originated at the Paleozoic Mesozoic contact. Trapping features visible on the seisnticlines include anticlinal closures, updip closures against nonnal faults, lateral pinchouts, angular unconfonnities, and onlap onto old highs.
Banzala Development Plan: Overcoming the Shallow Gas Hazard
Authors: Smith M.E. , Rieken M.K. , Streu D.J. , Gaona M.T. , Sousa J.
Published: October 2008

The Banzala Field, located offshore Cabinda, Angola, contains over one billion barrels of oil in place, in shallow water, at shallow depth and close to an existing infrastructure. The field was discovered in 1981, but the well was lost due to a blowout after reaching total depth.

The blowout resulted in the charging of a very shallow interval with over-pressure gas that now completely overlies the deeper oil reservoirs. The gas pressure was unknown, but believed to be very close to fracture pressure. Exact areal extent of the gas was unknown and it was not known if the system was static or continuing to charge from a deeper gas sand.

The field has not been developed because of the extent and uncertainty of shallow overpressured gas that overlies the deeper oil reservoirs and because of limited individual well productivity.

It was surmised that the outer limit of the shallow gas or gas/water contact (GWC) should correspond to a structural contour elevation such that the corresponding hydrostatic head of sea water exactly balanced the pressure of the gas bubble. Hydrostatic pressure data dating from 1983 was used to boundgas pressure between a maximum and minimum value. Consequently, it was believed, the vertical subsea depth of the GWC was bounded.

A dynamically positioned geotechnical vessel was chartered to drill along the calculated gas boundary. The effort was successful and appraisal wells have been drilled and evaluated.

Low well productivity will be solved by closely spaced wells on electric submersible pump (ESP). Well downtime and pump pulling costs are being minimized by deploying theESPs on coil tubing. A "hard landing" area is being designed into the platforms to support coil tubing equipment spreads.

Introduction

The Banzala Field is located in Blocks 34, 35, 45, and 46 in Area A of the Cabinda Concession, offshore Angola, West Africa (Figure 1) in approximately 125 to 175 ft of water. The hydrocarbon accumulation at Banzala occurs in three primaryreservoirs (Mesa, Lago, and Azul) between -1600 ft and -2000 ft tvdss. It is estimated that these sands contain over one billion barrels of oil in place. The productive oil bearing reservoirs are overlain by the Frio and Landana gas sands. The Frio is a naturally occurring overpressured gas sand at -1000 ft tvdss. The Landana was originally normally pressured, but has been supercharged with gas as a result of the discovery well blowout in 1981. The Landana is between -425 and -600 ft tvdss.

The Banzala Field is an anticline with four-way dip closure. The anticlinal structure (Figure 2) is well defined by six wells and 2seismic data. The crest of the anticlinal structure is difficult to resolve seismically because seismic data quality is locally degraded by shallow gas. Although amaximum of three faults have been mapped, additional faults that are not imaged with the current seismic data may be present.
An Alternative to API 14E Erosional Velocity Limits for Sand Laden Fluids
Authors: Salama Mamdouh M.
Published: October 2008

The current practice for eliminating erosional problems in piping systems is to limit the flow velocity (Ve) to that established by the recommended practice API RP 14E based on an empirical constant(C-factor) and the fluid mixture density (Pm) as follows:(available in full paper)

The API criterion is specified for clean service (non-corrosive and sand-free) and it is noted that the C-factor should be reduced if sand or corrosive conditions are present. The validity of the equation has been challenged on the basis that the API RP 14E limits on the C-factor can be very conservative for clean service and is not applicable for conditions when corrosion or sand are present. Extensive effort has been devoted to develop an alterative approach for establishing erosional velocity limits for sand laden fluids. Unfortunately, none of these proposals have been adopted as a standard practice because of their complexity, This paper will review the results of these studies and proposes an alterativeequation that is as simple as the API 14 E equation. This alterative Equation has the following form:(available in full paper)

The value of the S-factor depends on the pipe geometry, i.e. bend, tee, contraction, expansion, etc. Using the units for mixture flow velocity (Ve). in m/s, fluid mixture density (All) in kg/m3, pipe diameter (D) In rum and sand production (W) in kg/day, the value of the S-factor is 0.05 for pipe bends. The accuracy of the proposedequation for predicting erosion in pipe bends for fluids containing sand is demonstrated by a comparison with several multi-phase flow loop tests that cover a broad range of liquid-gas ratios and sand concentrations.

Introduction

Erosion is defined as the removal of material from a solid surface by the repeated application of mechanical forces. These forces are induced by solid particles, liquid droplets, or cavitations. Liquid impingement erosion occurs when liquid drops or liquid jet repeatedly impact the solid surface. Erosion may be attributed toremoval of the metal, the inhibited film, and/or protective corrosion scales. In order to avoid erosion damage, the current oil industry practice f()f sizing process piping, flow lines, pipelines, and tubing is to limit the now velocity to the maximum erosional velocity ascalculated by the following API RP 14 E equation (API, 1981, 1991)(available in full paper)

The Original API criterion is specified for clean service (noncorrosive and sand-free), and it is noted that the C-factor should bereduced if sand or corrosive conditions are present. However no guidelines are provided for these reductions. It has been argued by several investigators that the API RP 14E relation is extremely conservative under these conditions and this led to the changes in the 1991 edition. However, the recent changes imply that a C-factor of 100 is acceptable for corrosive systems and a C-factor of 150 to 200 is acceptable for inhibited systems.
Solar Cells with Enhanced Photocurrent Efficiencies Using Oligoaniline‐Crosslinked Au/CdS Nanoparticles Arrays on Electrodes
Authors: Yildiz Huseyin Bekir , Tel‐Vered Ran , Willner Itamar
Published: October 2008

Different configurations of CdS nanoparticles (NPs) are linked to Au electrodes by electropolymerization of thioaniline‐functionalized CdS NPs onto thioaniline‐functionalized Au‐electrodes. In one configuration, thioaniline‐functionalized CdS NPs are electropolymerized in the presence of thioanline‐modified Au NPs to yield an oligoaniline‐crosslinked CdS/Au NPs array. The NP‐functionalized electrode generates a photocurrent with a quantum yield that corresponds to ca. 9%. The photocurrent intensities are controlled by the potential applied on the electrode, and the redox‐state of the oligoaniline bridge. In the oxidized quinoide state of the oligoaniline units, the bridges act as electron acceptors that trap the conduction‐band electrons that are transported to the electrode and lead to high quantum yield photocurrents. The reduced π‐donor oligoaniline bridges act as π‐donor sites that associate N,N′‐dimethyl‐4,4′‐bipyridinium, MV2+, by donor/acceptor interactions, Ka = 5270 M−1. The associated MV2+ acts as an effective trap of the conduction‐band electrons, and in the presence of triethanolamine (TEOA) as an electron donor, high photocurrent values are measured (ca. 12% quantum yield). The electropolymerization of thioaniline‐functionalized Au NPs and thioaniline‐modified CdS NPs in the presence of MV2+ yields a MV2+‐imprinted NP array. The imprinted array exhibits enhanced affinities toward the association of MV2+ to the oligoaniline π‐donor sites, Ka = 2.29 × 104 M−1. This results in the effective trapping of the conduction‐band electrons and an enhanced quantum yield of the photocurrent, ca. 34%. The sacrificial electron donor, TEOA, was substituted with the reversible donor I3−. A solar cell consisting of the imprinted CdS/Au NPs array, with MV2+ and I3−, was constructed. The cell generated a photocurrent with a quantum yield of 4.7%.
The influence of natural variations in maternal care on play fighting in the rat
Authors: Parent Carine I. , Meaney Michael J.
Published: October 2008

Naturally occurring variations in maternal care in the rat influence the sensitivity of offspring to stress in adulthood. The offspring of mothers that show lower levels of pup licking/grooming (i.e., low‐LG mothers) demonstrate enhanced responses to stress and increased anxiety compared to those of high‐LG mothers. Low‐LG offspring are also more sensitive to the influence of environmental enrichment than high‐LG offspring. This study examined play fighting in the juvenile offspring of high‐LG and low‐LG dams in a multiple‐play partners housing environment. Male offspring from low‐LG dams demonstrated a significantly higher frequency of pouncing, pinning and aggressive social grooming than did high‐LG males and high‐LG and low‐LG females. Consistent with earlier reports, male pups engaged in more play fighting than did females and maternal care was associated with differences in play fighting but only in males. Lower levels of stimulation in the form of LG from the dam during perinatal development may thus increase sensitivity for the stimulating effects of play behavior in periadolescence, in part explaining the increased solicitation of play fighting through increased pouncing in the male offspring of the low‐LG mothers. These findings identify a possible influence of variations in maternal care on play fighting and suggest that maternal care in the perinatal period influence social interactions during periadolescence. © 2008 Wiley Periodicals, Inc. Dev Psychobiol 50: 767–776, 2008
Simvastatin impairs humoral and cell‐mediated immunity in mice by inhibiting lymphocyte homing, T‐cell activation and antigen cross‐presentation
Authors: Ulivieri Cristina , Fanigliulo Daniela , Benati Daniela , Laghi Pasini Franco , Baldari Cosima T.
Published: October 2008

Statins block the activity of HMG‐CoA reductase, which catalyses the production of mevalonate, an intermediate in cholesterol biosynthesis, which is also a precursor of isoprenoids. In addition to lowering circulating cholesterol, these drugs display anti‐inflammatory and immunomodulatory activities in vitro; however, their effects on the development of adaptive immune responses in vivo, as well as the underlying mechanisms, are as yet largely unknown. Here we investigated the outcome of simvastatin treatment on a number of processes, which together orchestrate adaptive immunity to specific antigen. Simvastatin treatment resulted in a marked reduction of T and B cells in spleen, lymph nodes and peripheral blood in mice. This effect could be ascribed principally to an impairment of lymphocyte homing to secondary lymphoid organs. In addition, simvastatin was found to strongly inhibit T‐cell responses to the MHCI restricted hen ovalbumin peptide antigen SIINFEKL and to impair ovalbumin uptake and cross‐presentation by MHCI. Simvastatin also suppressed antibody responses to immunization with ovalbumin and delayed‐type hypersensitivity to allergens. These activities could be largely accounted for by the simvastatin‐dependent inhibition of HMG‐CoA reductase. The data provide novel mechanistic insight into the activities of simvastatin in the highly complex context of the immune response.
Polyfunctional HCV‐specific T‐cell responses are associated with effective control of HCV replication
Authors: Ciuffreda Donatella , Comte Denis , Cavassini Matthias , Giostra Emiliano , Bühler Leo , Perruchoud Monika , Heim Markus H. , Battegay Manuel , Genné Daniel , Mulhaupt Beat , Malinverni Raffaele , Oneta Carl , Bernasconi Enos , Monnat Martine , Cerny Andreas , Chuard Christian , Borovicka Jan , Mentha Gilles , Pascual Manuel , Gonvers Jean‐Jacques , Pantaleo Giuseppe , Dutoit Valérie
Published: October 2008

HCV infection has a severe course of disease in HIV/HCV co‐infection and in liver transplant recipients. However, the mechanisms involved remain unclear. Here, we evaluated functional profiles of HCV‐specific T‐cell responses in 86 HCV mono‐infected patients, 48 HIV/HCV co‐infected patients and 42 liver transplant recipients. IFN‐γ and IL‐2 production and ability of CD4 and CD8 T cells to proliferate were assessed after stimulation with HCV‐derived peptides. We observed that HCV‐specific T‐cell responses were polyfunctional in HCV mono‐infected patients, with presence of proliferating single IL‐2‐, dual IL‐2/IFN‐γ and single IFN‐γ‐producing CD4+ and dual IL‐2/IFN‐γ and single IFN‐γ‐producing CD8+ cells. In contrast, HCV‐specific T‐cell responses had an effector profile in HIV/HCV co‐infected individuals and liver transplant recipients with absence of single IL‐2‐producing HCV‐specific CD4+ and dual IL‐2/IFN‐γ‐producing CD8+ T cells. In addition, HCV‐specific proliferation of CD4+ and CD8+ T cells was severely impaired in HIV/HCV co‐infected patients and liver transplant recipients. Importantly, “only effector” T‐cell responses were associated with significantly higher HCV viral load and more severe liver fibrosis scores. Therefore, the present results suggest that immune‐based mechanisms may contribute to explain the accelerated course of HCV infection in conditions of HIV‐1 co‐infection and liver transplantation.
Mouse CD146/MCAM is a marker of natural killer cell maturation
Authors: Despoix Nicolas , Walzer Thierry , Jouve Nathalie , Blot‐Chabaud Marcel , Bardin Nathalie , Paul Pascale , Lyonnet Luc , Vivier Eric , Dignat‐George Francoise , Vély Frédéric
Published: October 2008

CD146/melanoma cell adhesion molecule is an adhesion molecule expressed by endothelial cells and by a small fraction of activated T and B lymphocytes in humans. In order to analyze the pattern of CD146 expression in mouse leukocytes at steady‐state conditions, we generated a set of novel rat anti‐mouse CD146 monoclonal antibodies. CD146 expression was undetectable on monocytes, dendritic cells, T cells or B cells, but was expressed on about 30% of neutrophils and 60% of NK cells. Within murine lymphocytes, CD146 was defined as a novel NK‐specific surface molecule. An increased percentage of CD146+ cells was found in the most mature CD27−CD11b+ NK cell subpopulation, which also displays higher expression of Ly49C/I, Ly49D and KLRG1 and lower expression of NKG2A/C/E molecules. CD146+ NK cells were found to be less cytotoxic and produce less IFN‐γ than CD146− NK cells upon stimulation with target cells or activating antibodies. These findings define CD146 as a marker of mouse NK cell maturation that may be used as an alternative to the combined use of CD27 and CD11b staining to detect final stages of NK cell maturation.
Induction, function and regulation of IL‐17‐producing T cells
Authors: Mills Kingston H. G.
Published: October 2008

Recent reports have provided convincing evidence that IL‐17‐producing T cells play a key role in the pathogenesis of organ‐specific autoimmune diseases, a function previously attributed exclusively to IFN‐γ‐secreting Th1 cells. Furthermore, it appears that IL‐17‐producing T cells can also function with Th1 cells to mediate protective immunity to pathogens. Although much of the focus has been on IL‐17‐secreting CD4+ T cells, termed Th17 cells, CD8+ T cells, γδ T cells and NKT cells are also capable of secreting IL‐17. The differentiation of Th17 cells from naïve T cells appears to involve signals from TGF‐β, IL‐6, IL‐21, IL‐1β and IL‐23. Furthermore, IL‐1α or IL‐1β in synergy with IL‐23 can promote IL‐17 secretion from memory T cells. The induction or function of Th17 cells is regulated by cytokines secreted by the other major subtypes of T cells, including IFN‐γ, IL‐4, IL‐10 and at high concentrations, TGF‐β. The main function of IL‐17‐secreting T cells is to mediate inflammation, by stimulating production of inflammatory cytokines, such as TNF‐α, IL‐1β and IL‐6, and inflammatory chemokines that promote the recruitment of neutrophils and macrophages.
Stopping the traffic: A route to arthritis therapy
Authors: Hallett Maurice B. , Williams Anwen S.
Published: October 2008

The trafficking of immune cells to inflamed joints is the hallmark of rheumatoid arthritis. It has been known for years that neutrophils are abundant in the rheumatoid joints and have the potential to inflict tissue damage by the secretion of oxidants and proteases; however, the crucial role of neutrophil trafficking to the joints has only been demonstrated in recent years using transgenic mice and animal models of the disease. This finding opens the door to potential therapies based on inhibition of neutrophil trafficking. In this issue of the European Journal of Immunology, a study reports the use of antisense RNA to knock down the expression of cytosolic phospholipase A2α in mice. This has a major effect on neutrophil trafficking into inflamed joints and reverses the inflammatory swelling and tissue damage in the animal model used. This puts cytosolic phospholipase A2α, alongside its product leukotriene B4, on the list of potential targets for reducing cell trafficking to the joint in chronic inflammatory diseases like rheumatoid arthritis.