bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel, Surface Sensitive Approach to Quantitatively Measure the Prediction and Inhibition of Scale Growth
Authors: Wylde J. J. , Allen G. C. , Collins I. R. 
Published: December 2007

Abstract
A novel approach to measure mineral scale growth has been developed which is not only quantitative but also surface sensitive. In this study, a glass flow cell was used in conjunction with Laser Raman Spectroscopy to record the in-situ growth of mixed barium and strontium sulphate scale on the surface of 316 stainless steel. Studies of both uninhibited and inhibited growth are reported as well as the influence of specific ions. All experiments have been performed at room temperature and pressure and at constant solution pH.
In order to quantify these measurements, Secondary Ion Mass Spectrometry (SIMS) has been used to etch the precipitated scale from the surface of the steel. As the scale is removed, an elemental analysis of the sputtered ions is performed, resulting in a depth profile, which is sensitive to the presence of scale mineral ions on the steel surface. The etches were then imaged using Scanning Electron Microscopy (SEM).
Our data suggests that there was a large surface influence upon inhibition efficiency when compared with previously presented results (e.g. Yuan, 2000). A much higher concentration of inhibitor was required to prevent scale build up, compared with values determined in bulk precipitation tests, indicating the formation of inhibitorsurface complexes.
Most previous studies are non-surface sensitive and have utilised aqueous precipitation experiments to evaluate scale inhibition efficiency (Graham et al., 1997). Previous surface sensitive methods have used Atomic Force Microscopy (AFM) to observe scale precipitation and to measure the effect that nhibitors have upon the nature of crystal growth; however, this technique is not rate sensitive and thus the kinetics of scale build up have not been previously obtained (Bosbach et al., 1998).
Quantitative Prediction of Scale Depositions Induced by Oil Production: Application of the Thermo-Kinetic Software SCALE2000
Authors: Azaroual M. , Hurtevent C. , Kervévan C. , Brochot S. , Durance M.-V. 
Published: December 2007

Abstract
The SCALE2000 (V2.0) software (under Windows 95/98/NT) was specifically developed to predict quantitatively scale deposits induced by oil production operations. The conceptual model is based on the Pitzer's specific ion interaction formalism for Na-K-Ca-Mg-Sr-Ba-Fe-Cl-SO4-OH-H-Ac-CO3-HCO3-CO2-AcH-SiO2-H2O system under 25 - 250°C and 1 - 1000 bar conditions. SCALE2000 enables to perform four main kinds of calculations including solubility of the main known minerals responsible for scale problems in geothermal energy and oil productions (carbonates, sulphates, silicates, …), effect of temperature and pressure on the scale precipitations, effect of binary mixing of physico-chemical contrasted waters, quantitative predictions of scale formation based on a detailed kinetic formalism. As it was demonstrated by petroleum engineers, carbonate system is crucial for precise scale risk predictions. The reliability of SCALE2000 results was checked against measurements of individual mineral solubilities and kinetics found in the literature.
In this study, SCALE2000 was applied to the actual high temperature (164°C), high salinity (~ 84 g/l) and high pressure (320 bar) data of the Block 3 (Angola) oil-field. In agreement with observations, the precipitation of barite was predicted by SCALE2000. The mineralogical nature of deposits was intimately dependent on the reservoir water/seawater ratio. SCALE2000 simulations of the sulphate depositions on the tubing wall of the PAC 302B Pacassa well (block 3, Angola), as a function of the water produced, has permitted to predict the kinetics of barite precipitation for production P-T conditions (180 bar; 140°C). Simulation results were in good agreement with field observations.
Calcium Carbonate and Naphthenate Mixed Scale in Deep-Offshore Fields
Authors: Rousseau Guy , Zhou Honggang , Hurtevent Christian 
Published: December 2007

Abstract
Many of the fields that have been or will be discovered in the near future show signs of biodegradation of the crude oil. The result of such biodegradation is a decrease in the amount of the paraffins associated with the formation of naphthenic acids. Some of these crude oils may have a Total Acid Number (TAN) close to 5mg/g. When the reservoir fluid contains a significant amount of CO2, one can expect to find mixed scale of calcium carbonate and naphthenate. The aim of the work conducted was to assess the various factors which affect the formation of mixed scale.
We studied, in particular, the consequences arising from the formation of highly surface-active naphthenates which, depending on the nature of the cations in the formation water, can form stable emulsions, calcium naphthenate deposits or mixed scale of calcium carbonate and calcium naphthenate.
This paper presents the ways to prevent emulsions or deposits resulting from the formation of naphthenates. Chemical prevention is the most commonly used method but problems can sometimes be solved by modifying the way crude is processed. We will also describe an example of a modified process that we plan to use.
SQUEEZE Modelling: Current Best Practice and New Capabilities
Authors: Mackay E. J. 
Published: December 2007

Abstract
Various general-purpose software packages can be used to optimise the design of scale inhibitor squeeze treatments. However, the versatility and cost of these codes typically makes them cumbersome and expensive to use for optimising routine squeeze treatments. Conventional treatments should be modelled using purpose designed squeeze simulators that minimise data entry and facilitate quick extraction of results. However, misapplication of even a fit-for-purpose simulator can lead to incorrect treatment design. This problem is compounded by the fact that squeeze strategies are always being developed and refined, and the software must be developed to keep pace with these changes in technology if it is going to be applied correctly.
To deal with these twin issues, this paper will first describe how a squeeze simulator should be correctly applied, and what information may and may not validly be extracted. Potential pitfalls will be highlighted, as well as techniques for optimising the model set-up to ensure that the maximum amount of relevant data is utilised. Experience gained from use of the SQUEEZE V software for modelling core floods, single and multi-layer radial well models will be discussed, and the rationale for making certain decisions when building a model will be highlighted. Secondly, new features being introduced into this code are discussed, together with the impact these may have. The new facilities include two-phase flow, with the potential for component transport in the oleic phase, and full crossflow within the formation in addition to the well. Finally, the paper will present planned future developments that should improve the applicability and scope of the code, without increasing the difficulty of use unduly.
Integrating Well Production Data and 3D Seismic AVO Classification
Authors: Reymond S. B. , Matthews E. , Sissons B. 
Published: December 2007

Abstract
The Ngatoro Field in Taranaki, New Zealand has been producing for (9) nine years. Currently the field is producing 1000 bopd from 7 wells at 3 surface locations down from a peak of over 1500 bopd. The field has been analysed using new techniques in 3D seismic imaging to locate by-passed oil, and identify undrained pools. Three questions define the objectives of the study: Can we image reservoir pools in a complex stratigraphic and structural environment where conventional grid-based interpretation is not applicable due to lack of lateral continuity in reservoir properties?Can we distinguish fluids within each reservoir pools?Can extrapolate reservoir parameters observed at drilled locations to the entire field using 3D seismic data to build a 3D reservoir model?
This case study illustrates how 3D generalised inversion of seismic facies for reservoir parameters can be successfully applied to image and laterally predict reservoir parameters in laterally discontinuous turbidite depositional environment where hydrocarbon pools are located in complex combined stratigraphic-structural traps. Such conditions mean that structural mapping is inadequate to define traps and to estimate reserves in place. Conventional seismic amplitude analysis has been used to aid definition but is not sufficient to guarantee presence of economic hydrocarbons in potential reservoir pools.
Using new 3D seismic attributes such as bright spot indicators, attenuation and edge enhancing volumes coupled with 6 AVO (Amplitude Versus Offset) volumes integrated into a single class cube of reservoir properties, made the mapping of reservoir pools possible over the entire data set. In addition, 4 fluid types, as observed in more than 20 reservoir pools were validated by final inverted results to allow lateral prediction of fluid contents in un-drilled reservoir targets.
Well production data and 3D seismic inverted volume were later integrated to build a 3D reservoir model to support updated volumetrics reserves computation and to define additional targets for exploration drilling.
Umm Gudair Dumpflood Pilot Project, The Applicability of Dumpflood to Enhance Sweep & Maintain Reservoir Pressure
Authors: Quttainah R. , Al-Hunaif J. 
Published: December 2007

Abstract
Historical production (spanning almost 30 years) has confirmed that the UG (MO) reservoir receives very little natural pressure support in some areas. This has resulted in a declining reservoir pressure (from 4050 to 3200 psi) and low recovery factor and also, areas of poor water sweeping. The remedial plan is to initiate a full field water injection project to increase reservoir pressure, improve sweep and enhance oil recovery.
A dumpflood pilot project was initiated to prove the viability of and quantify sweep benefits of water injection in the B-zone of the MO reservoir. The dumpflood Pilot aims to prove that water flooding can enable this unswept oil to be produced and provide data to support the design of future Full Field Water Injection Project.
A dumpflood operation is basically injecting water into the recipient reservoir from a water source reservoir by the natural force of gravity and the pressure differential of the two reservoirs using the same well. In the Umm Gudair Dumpflood Pilot, the water bearing source reservoir is the Zubair formation. The recipient reservoir is the B-zone in the MO. And since the Zubair is structurally higher than the MO, and the reservoir pressure of the Zubair is higher than the MO, water was being produced from the Zubair and injected into the MO by the natural force of gravity and the pressure differential between the two reservoirs.
A location in the east flank of east UG field was chosen to allocate the dumpflood pilot well. This was done after going through 4 different locations in the field to allocate the most suitable field location.
Surveillance requirements have been identified for the UG dumpflood pilot. This surveillance plan involves the dumpflood injection well and 4 other observation wells. In addition to regular PLT surveys, to determine zonal injection profiles and ongoing corrosion surveillance in the Dumpflood well, additional pressure surveys on adjacent wells were planned. It was also planned to utilize radioactive tracers to monitor breakthrough and develop an understanding of the pattern of sweep.
Technical Contributions:
Demonstrated the design of a water dumpflood method to analyze injectivity & water sweep. Established a cost-effective technique to quantify injectivity and water sweep. Demonstrated the applicability of dumpflood to re-pressurize a constantly depleting reservoir.
Surfactants Oil Displacement System in High Salinity Formations
Authors: Wang Yefei , Li Jiyong , Zhao Fulin 
Published: December 2007

Abstract
Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena[1], A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl2. By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied, LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine, water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field.
The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%.
Now the four field tests get along favorably, verifying good result and indicating bright application prospect.
Evaluation of a New Thermally Stable Polycrystalline Diamond Material
Authors: Zacny K. A. , Cooper G. A. 
Published: December 2007

Abstract
Comparative wear tests were carried out on different composites of synthetic diamond bonded by silicon carbide, by machining rock cylinders in an instrumented lathe. The composites included Syndax3, ‘Polycubes(TM)’ from Didco Inc, and a new material known as ScD from Skeleton Technologies Inc. The different materials show different wear behavior. In particular, Syndax3 wears slowly, by a process that involves predominantly a polishing of the cutter surface. The result is that although the wear rate is low, the cutter points eventually become polished and the cutters lose performance. In contrast, the ScD material wears more rapidly, but maintains a more aggressive behavior since new, sharp diamonds are continuously being exposed. As a result, it keeps an ability to cut rock effectively at much greater states of wear. The material from Didco Inc has a behavior that is intermediate between that of the other two types.
A New Analytical Model for the Prediction of Fluid Production and Gas Consumption of Gas Chamber Pumps
Authors: Hernandez Ali , Caicedo Sergio , Marcano Luisana , Brown Juan 
Published: December 2007

Abstract
Recent experimental studies on intermittent gas lift have shown that the lift efficiency of this method decreases drastically as the viscosity of the fluid to be lifted increases. As the viscosity increases more gas is needed to keep the fallback losses at a minimum. One way to get around this problem and eliminate fallback losses is to implement the use of Gas Chamber Pumps (GCP's).
GCP's are highly appropriate for shallow wells producing heavy oil in places where high-pressure injection gas is available. That is the case of some wells in Lake Maracaibo and in some places in the eastern oil fields in Venezuela that are currently producing oil of 14 to 23°API from reservoirs located at depths between 2000 and 3500 ft.
A variety of different GCP configurations can be found in the literature, from highly complex and compact units to simple types of completion that can be implemented with minor changes of current gas lift completions. The advent of simple and highly reliable programmable surface controllers is making it possible to simplify subsurface completion. The simplicity of these new completions implies a new and economical way of implementing GCP's where they are appropriate.
A description of how different GCP's work and the most popular configurations are given in this paper. It is also explained in detail a new and simple engineering procedure to estimate the liquid production and gas consumption of a well producing with a GCP. This procedure takes into account the inflow capability of the well and couples this capability with the pressure losses across the different parts of the completion and the flow and pressure capacity of the gas lift system.
New Gas-Lift Pilot Valve Increases Gas-Lift Efficiency
Authors: Hernandez Ali , Perez Cesar , Villalobos Balmiro , Romero Analis , Wildman Sam 
Published: December 2007

Abstract
The most important component in an intermittent gas lift installation is the pilot valve. Its selection and proper calibration determine the success of the gas lift design. Recent tests performed in a field scale installation equipped with an experimental well and careful observations of the performance of real wells on intermittent gas lift in Lake Maracaibo have shown the importance of the proper selection of the area ratio of the pilot section and the main port diameter. Usually, the designer has a variety of area ratios of the pilot section to choose from and its selection will depend on the type of gas lift operation, choke controlled or use of time-cycle controllers, and the volume of gas needed per cycle. In some cases, the lowest commercially available area ratio will still be too large with the result of not being able to inject below a certain volume of gas per cycle. The over-injection per cycle takes place because the minimum spread attainable is greater than needed. This situation occurs when the tubing-casing annulus is large and the valve size that can be installed in the well is smaller than the 1 1/2-inch valve. Hundreds of wells in Lake Maracaibo with 7-inch casings and 2 7/8-inch tubing can not be efficiently lifted because of the lack of commercially available pilot valves with small area ratios.
The diameter of the main gas injection orifice is a fixed value for a particular valve model. The size of this orifice is important for two reasons: The size of the injection orifice, together with the injection pressure and tubing load, determines the velocity of the liquid slug being lifted. If the size of the orifice is too small, which is usually the case for 1-inch size valves, the liquid fallback is increased due to low liquid slug velocities.Small injection orifice diameters increase gas injection time and therefore limit the liquid production of the well, especially if the optimum cycle time is of short duration.Tests performed in an experimental well, and presented in this paper, show how a new 1-inch pilot valve design was able to increase the gas lift efficiency. The main features of the new gas lift valve, its calibration procedure and its performance in several real wells are also presented in this paper.
Downhole Oil/Water Separation System – Field Pilot – Secondary Recovery Application Project
Authors: Scaramuzza J. L. , Fischetti H. , Strappa L. , Figliuolo S. 
Published: December 2007

Abstract
It is widely known the adverse impacts that the continuous increase in the volume of produced water has on oil production operation and reserves recovery.
New technologies have been successfully developed and implemented to minimize de economic and environmental consequences of water production.
The Down hole oil/water separation system (DOWS), which was developed by the Centre for Engineering Research Inc. (CFER), allows to separate the produced water down hole and its later injection on the same well.
The system has proved to be technically and economically profitable in mature reservoirs reducing the lifting cost, production facilities cost and environmental risk associated with the handling of large volumes of produced water at surface.
Repsol-YPF produce, separate, treat and dispose of over half million barrels of water per day in La Ventana and Vizcacheras fields in the Cuyo basin in Mendoza province. They produce 29 and 30 °API oil respectively with a high percentage of water.
A pilot field trail was carried out in these fields using DOWS technology. This equipment was installed on two wells producing with electrical-submersible pumps, one in VM-097 well (La Ventana) and the other in Vi-284 well (Vizcacheras).
This report describes the separation system implemented, the candidate wells selected, the results of the pilot field trails and the current flooded project based on Vizcacheras pilot result.
Tácata Field: Discovering Oil in a Subthrust Triangle Zone
Authors: Sadler Peter , Manceda Rene , Franco Alejandro , Vukelic Miguel , Coria Carlos 
Published: December 2007

Abstract
The Tácata Field lies some 30 km west of the prolific El Furrial trend of oil fields in the Eastern Venezuela Basin, and was discovered in 1997. It lies within a recently active triangle zone and presents significant problems to seismic imaging. Pre-stack depth migration and map migration techniques have been employed, the latter with particular success. The seismic interpretation is constrained within the framework of a three dimensional balanced structural model.
A Decision-Making Expert System for the Oil Transport System
Authors: Abdulah Abdulatif , Islam Rafiqul 
Published: December 2007

Abstract
The problem of pipeline corrosion within the oil and gas industry costs the world economy billions of dollars every year in maintenance, repairs and too often in damage control. These costs are passed on, reflected in increased prices to the world's petroleum product consumers. With the advent of widely available computing and communications technology, it is logical that we should seek relief from corrosion and maintenance problems in the form of a high-tech solution. To this end the authors have developed an expert system, the Petroleum Corrosion and Coating Expert System (PCCES) equipped with an extensive knowledgebase of physical and chemical phenomena and the metallurgical characteristics of the pipes themselves. Essentially a complex decision tree, the expert considers factors in a real-world situation and attempts to produce appropriate conclusions based on inference from the knowledgebase. For greater ease of use, the expert system relies on a Java applet design, eliminating the need for proprietary client-side software.
Measurement and Modeling of Wax Deposition in Crude Oil Pipelines
Authors: Nazar A. R. Solaimany , Dabir B. , Islam M. R. 
Published: December 2007

Abstract
One of the problems faced by the petroleum industry is the wax deposition in pipelines during transportation of waxy crude oil. Oil companies dealing with waxy crude often spend millions of dollars in remedial procedures. An ideal design should use an accurate mathematical model that would include all salient features of wax deposition and waxy crude transport to predict wax deposition during crude oil transportation. In this paper, a comprehensive mathematical model for quantitative prediction of wax deposition for a multicomponent hydrocarbons mixture (oil) has been developed. The wax deposition is estimated from the diffusion of wax from the bulk towards the wall as a result of temperature gradients. Parametric studies on the variation of the amount of wax deposition were performed for a mixture of toluene and oil wax cut in an experimental setup. Overall predictive ability of the proposed model is excellent for the laminar flow.