bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multifunctional Chemicals for West African Deep Offshore Fields
Authors: Poggesi Guido , Hurtevent Christian , Buchart David 
Published: December 2007

Abstract
In Deep Offshore Fields, the injection of chemicals demands the installation of expensive and complex systems.
When the Girassol and Dalia projects, on the Block 17 in Angola, were undertaken, the Operator decided to limit the number of liners for continuous injection to one.
Through this liner, a Scale and a Corrosion inhibitor will be injected at the bottom of the well. In the near future, when the water cut becomes relevant, a demulsifier could be also injected.
The liner can also be used occasionally, for the injection of methanol, in order to remove the hydrate plugs.
The paper presents the research and development undertaken to determine the different molecules (scale and corrosion inhibitors plus demulsifiers) and their compatibilities, as well as the compatibility with any other fluid that could come in contact with the additive.
The multifunctional chemical that has been especially formulated for this application, contains three different products dissolved in the same solvent, even if, generally, they are soluble in different fluids.
The advantage of such a solution is that the percentages of each of the three base compounds can be adapted to the production conditions and the evolution of the water cut, without affecting their stability.
The solution of the compatibility problems has represented a real challenge. The three active substances should not only be mutually compatible, but the product itself has to be compatible with other fluids likely to be injected through the liner. These would include methanol, used for the prevention of hydrates, or glycols, for the preservation of the liners during the shut-down periods.
The last major challenge was to obtain a stable blend presenting a very low viscosity, capable of being injected over long distances and at low temperatures with a minimum pressure drop.
Assessing the Potential of Atomic Force Microscopy to Study the Formation of Electrodeposited Calcareous Scales in Uninhibited and Inhibited Conditions
Authors: Neville A. , Bepoix M. , Graham G. , Morizot A. P. 
Published: December 2007

Abstract
An important feature of cathodic protection in seawater is the formation of calcareous deposits; a term, which is often used to describe magnesium (e.g. Mg(OH)2) and calcium containing (e.g. CaCO3), compounds. Deposition involves the nucleation and growth of minerals on a metallic surface from the interfacial solution, which is supersaturated with respect to certain compounds.
Electrodepostion offers a controlled method of generating surface scaling deposits and, as such, there is potential for using electrodeposition to assess the efficiency of scale inhibitors and the rate of nucleation and growth of crystals on solid surfaces.
In this study the development of scale on a stainless steel surface through application of a cathodic potential in different brine systems has been used to follow deposition of Ca- and Mg-containing compounds on the surface in uninhibited and inhibited conditions. The focus of this paper is in the potential of atomic force microscopy as a method for assessing the mechanisms and the rate of formation of scale. Some preliminary ex-situ tests were conducted to probe the kinetics of scale formation and the dependence on applied potential. Preliminary tests using in-situ AFM were conducted and some promising results are presented.
Scale and Naphthenate Inhibition in Deep-Offshore Fields
Authors: Goldszal Alexandre , Hurtevent Christian , Rousseau Guy 
Published: December 2007

Abstract
Many of the fields that have been discovered recently in the West African deep-offshore will produce acidic crudes associated with gas containing a high concentration of CO2.
During the oil production process, a pH increase due to decompression and carbon dioxide degassing may generate surface-active naphthenates that can drastically stabilize emulsified water in crude oil. These may also combine with metal cations present in the reservoir water and form deposits. In all cases, production operations may be seriously disturbed.
The aim of the work conducted was to assess naphthenate and scale inhibition and the various factors that can affect its efficiency. In particular, we studied scale inhibitor interactions on naphthenate prevention.
This paper presents the results of studies on emulsion stability and naphthenate deposit formation, evaluated for various acidic crudes. As the pH increased, various behaviors were observed: progressive emulsion stabilization or abrupt transitions from unstable to stable emulsions. Naphthenate deposits formed in some cases even at low pH. Such a diversity of behaviors was explained in terms of differences in acid natures.
To prevent emulsion stability and naphthenate deposits, selected demulsifier and scale inhibitor additives were then tested. Several types of demulsifiers were found to be efficient at both emulsion-breaking and naphthenate deposit inhibition. In some cases, mixtures of demulsifiers and scale inhibitors produced very good results, highlighting a synergetic effect between the two additives. Unfortunately, the use of scale inhibitors generally increased the calcium content of the oil phase. Basically, the use of scale inhibitor with acidic crudes degrades the oil quality in terms of water cut and metal content.
A Protocol to Inhibit the Formation of Natrium Chloride Salt Blocks
Authors: Kirk Joseph W. , Dobbs James B. 
Published: December 2007

Abstract
In many parts of the world, petroleum is produced from reservoirs, which also produce brine water that is near saturation with respect to sodium chloride salt. During the course of producing these fluids, salt crystals form and grow to a point that a "salt block" occurs in the well and/or flowlines. The mechanisms of formation vary, but most often it follows one of two scenarios: Temperature cooling, as the fluids are transported from the reservoir to the surface, causes the temperature to drop. Saturation occurs and deposition begins.Concentrating of the brine downhole as produced gas strips water, leaving the salt behind concentrating the solution of sodium chloride brine. Salt blocks occur as the deposit grows.
Laboratory testing has identified at least two types of additives that will function as a sodium chloride scale inhibitor. From this data, field applications have been designed and applied.
This paper will describe the chemical testing, the field application by three application methods, and discuss field data that illustrates successful salt block inhibition.
The Importance of Appropriate Laboratory Procedures for the Determination of Scale Inhibitor Performance
Authors: Graham G. M. , Collins I. R. , Stalker R. , Littlehales I. J. 
Published: December 2007

Abstract
Inhibitor performance in terms of the minimum inhibitor concentration (MIC) or the threshold concentration required to prevent scale is the most important aspect for scale control additives. The laboratory test protocols adopted throughout the industry are very similar and are based upon static "bulk" inhibition performance tests and dynamic "tube blocking" inhibitor performance tests. However it has become evident from field selection studies that performance results, obtained from different laboratories using similar techniques, can be significantly different.
In this paper the various procedural differences are described. Results are presented from an extensive series of comparative performance tests examining both static and dynamic performance against calcium carbonate and barium sulphate scale. The results clearly demonstrate how relatively small differences in test procedure, as currently adopted by different laboratories, can have a significant impact on determined MIC values and comparative performance of different species. Such procedural modifications can therefore impact upon the reliability of data obtained in field chemical selection studies and the determination of dose levels, leading to the selection of less effective products. Tests examine the comparative performance2,3 and for selecting scale inhibitor products prior impact of test procedures on generically different inhibitor species including phosphonate, polyacrylate and polyvinylsulphonate chemistries. The impact of the following aspects are covered: The inclusion of bicarbonate ions on both static and dynamic barium sulphate performance tests.The manner in which pH adjustment impacts dynamic sulphate and carbonate performance tests.Effect of flow rate, un time, coil dimensions and pre-scaling on dynamic barium sulphate and carbonate performance tests.
Significant changes in both MIC values and also product ranking are recorded using variations on the standard test protocols commonly used in different laboratories, which demonstrates that more standardised and field appropriate procedures are required. The results in terms of changes in MIC and ranking of the different products are then explained mechanistically based upon the properties of the different products and the impact of modifications to test procedures. Examples of comparative performance for particular field cases are shown which demonstrate the importance of a field appropriate procedure. Finally, recommended test protocols will be detailed based upon the findings of this study.
Water Shut-Off Treatments In Open Hole Horizontal Wells Completed With Slotted Liners
Authors: Arangath R. , Mkpasi E. E. 
Published: December 2007

Abstract
This paper describes a water shut-off treatment on a horizontal well in a field operated by Mobil Producing Nigeria (MPN) offshore Nigeria. The well was initially completed with an uncemented slotted liner in a highly permeable formation. The field location and pre-treatment well completion schematic are shown in Figures 1 and 2 respectively. The intervention was carried out with the use of coiled tubing through the existing production tubing string. Figure 1Location of MPN’s well XFigure 2MPN’s well X pre- treatment completion schematic.
On inception of production this well showed water cuts well above those normally expected. The high water cut, with the attendant reduction in produced oil, was not expected from a review of the geological and reservoir data of the formation. Therefore a coiled tubing conveyed production log was acquired to identify water entry points. Interpretation of the logs showed that the water was entering from a short section located approximately in the middle of the horizontal drain hole. It was observed that there was no contribution to (oil) flow below this zone, which was also found to be the deepest in the horizontal section and hence closest to the oil/water interface.
The section was therefore sealed off to increase oil production and maximize recovery from the section of the reservoir in which the well was drilled. The secondary objective was also to free the pipeline and other production facilities of this unwanted fluid (water).
A through tubing inflatable bridge plug and cement retainer were set respectively above and below the water entry section to provide a means to retard water production.
The water entry section of the horizontal wellbore was sealed off with a polyacrylamide gel. This gel was specifically tailored to seal off behind the slotted liner and prevent any flow back of polymer in the annular section that was contributing to oil flow. The treatment was performed in 3 days and the well was left closed-in for 2 days to allow the polymer to cure. The well was later reopened and it flowed spontaneously.
Post treatment production tests showed a decrease in water cut of approximately 70% while the corresponding oil gain was in excess of 25%. These figures have been maintained for at least 1 year after the treatment.
Based on these results two other similar treatments (designated as well Y and Z) have been performed for a minor operator in Nigeria. The results of these two treatments are also presented.
Coiled Tubing in High-Pressure/High-Temperature Wells—Technical Enhancements in the North Sea
Authors: Ponsonby Miles , McClellan Nick , Ligertwood John 
Published: December 2007

Abstract
This paper presents an overview of coiled-tubing (CT) innovations and perforating-tool enhancements that have been developed in recent years to meet the challenges of coiled-tubing perforating in high-pressure, high-temperature (HPHT) well environments in the North Sea, specifically on TotalFinaElf’s Elgin and Franklin fields.
Key areas covered include: the manufacturing and inspection of coiled tubing; new pressure-control equipment for pressures up to 15,000 psi and temperatures up to 390°F; installation, operation, and maintenance of surface equipment; downhole tools; perforating tools; elastomers; well fluids; contingencies; best practices; and future solutions.
Full-Scale Tests Prove it Practical to "Drill" Holes with Coiled Tubing Using Only Acid; No Motors, No Bits
Authors: Portman Lance , Rae Phil , Munir Antares 
Published: December 2007

Abstract
This paper details the results of a test program designed to show that acid can be used to construct clean, defined wellbores in carbonate rocks. The results show that with the correct choice of nozzle layout, acid strength and jetting pressure, holes can be constructed at commercially attractive rates.
Variable OD Coiled Tubing
Authors: Newman Ken , Martin John 
Published: December 2007

Abstract
This paper presents the concept of coiled tubing (CT) with a continuously varying outside diameter (OD) over a substantial portion of its length. Potential applications for variable OD CT (VODCT) are discussed to show why this concept is being considered. The changes required to conventional CT surface equipment to handle VODCT are discussed. Finally, possible manufacturing techniques are discussed for making VODCT.
Solutions to Coiled Tubing Depth Control
Authors: Flowers J. K. , Nessim A. E. 
Published: December 2007

Abstract
Evolution of coiled tubing services requires greater down-hole depth accuracy. Depth critical jobs include coiled tubing conveyed perforating, zonal isolation and plug setting, among others.
Coiled tubing depth measurements are performed at surface, using devices to measure the length of coil tubing being deployed in the well. Measurement methods and their procedures have varied over time and have been continuously developed and improved on in an attempt to achieve higher degrees of accuracy and reliability in the length measurement. By principle, these methods provide a measurement of the length of the pipe deployed into the well but may considerably differ from the true depth of the coil end due to down-hole deformation of the coil tubing.
Various factors influence the down-hole deformation of the coil tubing; among these factors are temperature and pressure effects on the pipe. Elastic deformation of the pipe due to its own weight, sinusoidal and helical buckling effects occur and can substantially affect true depth. In view of this complexity, down-hole depth correlation is executed in depth critical jobs using various techniques, such as; tubing end locator, wireline logging tools, memory runs and reference depth tagging technique.
This paper discusses the different methods of surface pipe length measurement, their historical developments and the errors in true depth from measured depth due to down-hole deformation of the coil tubing. We present the results of a newly developed tool, DepthLOG, that provides a reliable and accurate down-hole depth correlation without the drawbacks and expense of other currently used down-hole depth correlation runs.
Cost Reduction and Injectivity Improvements for CO2 Foams for Mobility Control
Authors: Grigg Reid B. , Tsau Jyun-Syung , Martin F. David 
Published: December 2007

Abstract
This paper identifies chemical cost reduction derived from the synergistic effects of co-surfactant systems using a good foaming agent and a less expensive poor foaming agent. The required good foaming agent is reduced by at least 75%. Also the effect on injectivity is reduced by as much as 50% using the co-surfactant system, compared to a previously used surfactant system. Mobility control of injected CO2 for improved oil recovery can be achieved with significant reduction in the chemical cost of SAG, improved injectivity of SAG, and improved economics of CO2 injection project when compared to reported systems.
New Insight on Polymer Adsorption Under High Flow Rates
Authors: Chauveteau G. , Denys K. , Zaitoun A. 
Published: December 2007

Abstract
In previous papers we investigated high-molecular-weight polyacrylamide adsorption under high shear rates in low-permeability media and found that, above a critical value γc, adsorbed macromolecules can reduce the permeability by factors over hundred, suggesting a mechanism of pore throat bridging. New lab experiments have been designed specifically to elucidate the mechanism at the origin of this "bridging adsorption". Polymer injections were carried out over a wide range of shear rates in homogeneous high-permeability granular packs having hydrodynamic pore throats too large to be bridged by polymer macromolecules. When polymer is injected at low shear rate (γ &lt; γc) the adsorbed layer thickness εHS (calculated from permeability reduction values) does not depend on injection rate. When the injection occurs at higher shear rates (γ &gt; γc), εH increases slowly up to reach maximum values εHM increasing with injection shear rate. These εHM values were found to be large enough to explain the very high reductions in permeability obtained previously in low-permeability packs.
These results show that polymer adsorption in porous media can be increased significantly by the hydrodynamic forces normal to the pore wall, as soon as they become high enough to "push" additional macromolecules into the already adsorbed polymer layer. This mechanism increases both polymer adsorption density and adsorbed layer thickness. We propose to refer to this mechanism as a "flow-induced adsorption". This new interpretation is consistent with all results previously attributed to "bridging adsorption" and the new results reported in this paper. It provides an important conceptual tool to model polymer placement in water shutoff and to design conformance treatment.
Time-Dependent Shape Factors for Interporosity Flow in Naturally Fractured Gas-Condensate Reservoirs
Authors: Penuela G. , Civan F. , Hughes R. G. , Wiggins M. L. 
Published: December 2007

Abstract
A rigorous interporosity flow equation incorporating a time-dependent shapefactor is derived and validated for improved dual-porosity modeling ofnaturally fractured gas-condensate reservoirs. The equation expresses theinterporosity molar rate in terms of the pseudo-pressure gradient in thematrix, fracture surface area, matrix permeability, and a variable matrix-blockshape factor. This approach can accommodate the flow directed from matrix tofractures in a simulator that represents the permeability of the interconnectedfractures by a tensor inside each grid-block. This feature distinguishes thismodel from the popular sugar-cube approach to modeling naturally fracturedreservoirs.
Compositional simulation is performed to verify the flow equation using thetime-dependent shape factor. Numerical experiments with various matrix-blocksizes indicate that the shape factor varies with time but converges to valuesderived by Lim and Aziz (1995). The average matrix-pressure location in thematrix block shifts from near the fracture face to the block center as thefluid flows from the matrix into the fracture. This phenomenon indicates thatneglecting the time dependency of the shape factor can introduce significanterrors in numerical simulation of naturally fractured reservoirs. The timedependency can contribute significantly to fluid production once the pressurefront moves through the reservoir along the highly permeable fracture network.This phenomenon is not considered in present commercial simulators that usepseudo-steady state factors.
The model equations are expressed in dimensionless form so they can bereadily integrated into current simulators. The dimensionless time used in theproposed method includes pseudo-functions that capture multiphase effects ofthe gas-condensate systems. Applications to single- and multiphase black-oilsystems are also discussed.
A New Method of Calculating Reservoir Pressure in Real Time
Authors: Foo David 
Published: December 2007

Abstract
Real-time data contains a record of the producing conditions in a well. This data is used for production reporting but is seldom used directly to analyze production problems. In fact, to fully realize the value of real-time data, new analysis techniques need to be formulated.
Part of the problem with using real-time data relates to the nature of conventional production engineering methods. Accepted techniques attempt to model well behavior using steady-state behavior, when in fact well behavior is constantly changing. Conventional nodal analysis uses a "snapshot" of data, taken at a single moment in time, which may or may not be representative of the well's behavior.
Real-time data, on the other hand, presents the unsteady-state behavior of a well, reflecting the subtle variations in all aspects of the production system (including flowlines and facilities). However, the equations for unsteady-state analysis are generally very complex and impractical for day-to-day analysis.
In investigating the best approach for using real-time data to analyse well problems, methods of combining time-based data with steady state analysis techniques were examined. From this work, a new method for calculating reservoir pressure from wellhead data was discovered. This method does not require any knowledge of cumulative production or initial reservoir pressure, but yields a result that can be within 5% of that measured by performing a buildup test. Advantages of this method include: Normal day-to-day flow data is used, so the well does not need to be shut in to gather data.Results are available immediately.The method is simpler both mathematically and logistically.The data required is gathered as a part of mandatory production reporting, so historical data can yield the reservoir pressure at any point in the well's past.
This paper presents the method developed for calculating reservoir pressure from SCADA data. Several real world examples are presented, limitations of the method are reviewed, and further enhancements are discussed. Most importantly, this paper highlights the value available through analyzing the real-time data acquired by SCADA systems.