bluuebunny/crossref_metadata_2025_split huggingface dataset:
Membangun Komunikasi Efektif Antara Pendidik Dengan Peserta Didik Dalam Perspektif Islam
Authors: Aminah Siti 
Published: April 2016

<span><em>Teacher who able to effective communication with student, of course they </em><span><em>will optimize the effectiveness of their job gives instruction to the student </em><span><em>become the faithful man. Al-Qur’an and Al-hadith as the guidance of </em><span><em>human discusses clearly how to make effective communication. Effective </em><span><em>communication is communication which is use good language both of verbal </em><span><em>and nonverbal appropriate with the situation and condition so the purpose </em><span><em>of communication will be achieved. Model of Teacher Communication </em><span><em>that explain in Al-Qur’an are: 1) Qaulan Balighan: the model of teacher </em><span><em>communication to touch cognitive and affective aspect of student, 2) Qaulan </em><span><em>layyinan: flxible communication model of teacher for student who have </em><span><em>bad character, 3) Qaulan Ma’rufa: the model of teacher communication </em><span><em>with student as their parents, 4) Qaulan Maisuran: the model of teacher </em><span><em>communication who has been unable to fulfil the demand of students who </em><span><em>fid diffiulty, 5) Qaulan Karima: model of teacher communication with </em><span><em>someone who are older or higher status, 6) Qaulan Sadida: model of teacher</em><br /><span><em>communication remind the students emphatically. Prophet Muhammad SAW </em><span><em>as the teacher has good communication therefore acceptable by His Ummah </em><span><em>and followed all his deeds and says. The best teachers are teachers who are</em><br /><span><em>able to provide the best educational method which is able to communicate </em><span><em>with the students using best way of communication.</em><br /><span><strong>Keywords: </strong><span><em>Effective Communication, Teacher, Student, Islam.</em></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span></span><br /><br class="Apple-interchange-newline" /></span></span>
La Formación Continuada en Drogodependencias
Authors: Becoña E. , Bobes J. 
Published: April 2016

La formación continuada ha sido una de las grandes inquietudes de los profesionales de las drogodependencias desde el primer momento. El autodidactismo y el reciclaje sin contrastar dominó la primera época para luego pasar a una formación reglada y de calidad. Las Sociedades Científicas primero y luego estas mismas coordinadamente con Universidad y administraciones autonómicas han conseguido que en estos momentos la formación de postgrado en España presente el mejor nivel de toda Europa, ya sea por medio de Masters Universitarios o mediante la formación de expertos en drogodependencias. Socidrogalcohol como sociedad científica, con largo bagaje en la formación continuada y reciclaje de sus miembros, consciente del papel transcendental que debe desempeñar en la docencia ha decidido hacer una apuesta por la creación de un marco estable anual donde la formación de calidad y actualizada a las nuevas exigencias del mundo de las toxicomanías sean el objetivo fundamental, por lo que en este año 2000 inicia una nueva andadura con la Escuela de Otoño en Drogodependencias de Socidrogalcohol.
Design and Performance of Novel Sulphide Nanoparticle Scale Inhibitors for North Sea HP/HT Fields
Authors: Baraka-Lokmane S. , Hurtevent C. , Rossiter M. , Bryce F. , Lepoivre F. , Marais A. , Tillement O. , Simpson C. , Graham G. M. 
Published: April 2016

Abstract
Numerous challenges exist in Total's Central Graben Area (CGA). The main reason being that they present extremely "hard" conditions: high temperature (with 195°C to 225°C due to reverse Joule Thomson effect), high pressure (with 1,100 bar), high salinity (with more than 250g/L in TDS, more than 20g/L in calcium and circa 450mg/L in iron) along with several scale types (with sodium chloride, calcium carbonate, zinc sulphide and lead sulphide).
In the wells of CGA fields, the highest scaling risk is the formation of sulphide scale in the subsurface safety valve region. Commercially available scale inhibitors have proven incapable to perform under such "hard conditions" (see SPE 173761).
This paper describes the design process of suitable new chemicals (scale inhibitors and nanoparticles scale inhibitors) for both downhole continuous injection and squeeze treatment applications.
Such compounds are based on cationic polymers and sulphonated anionic polymers. A chemical approach has been used for the synthesis of silica nanoparticles. The sol-gel method, in addition to its low cost, allows controlling both the size and morphology of the particles by varying certain parameters of the reaction. Extensive laboratory tests have been performed for the validation of these products; these tests include scale inhibitor/brine compatibility, static and dynamic tests, thermal ageing, post ageing analysis and performance tests as well as coreflood tests using real core from the CGA formations. These laboratory testing have allowed the tuning of the chemical design of these novel products in order to improve the performance and the thermal-stability.
This paper describes the considerable advancement in chemical performance under these extreme conditions, including specific test development for lead sulphide which has to date proven more difficult than other sulphide scales to assess under field representative conditions in the laboratory. The newly developed chemicals are now ready for trial on the field.
Time-Resolved Fluorescence for Real-Time Monitoring of Both Scale and Corrosion Inhibitors: A Game-Changing Technique
Authors: Marais A. , Martini M. , Lepoivre F. , Ould-Metidji M. , Collet A. , Tillement O. , Hurtevent C. , Baraka-Lokmane S. 
Published: April 2016

Abstract
Inhibitor products have been widely used to reduce both steel corrosion and scale deposition on pipelines, tubings and safety valves in critical offshore sites. Their simultaneous injection with brine has gradually increased the lifetime of production wells with incontestable benefits for the oil and gas industry. However, the large use of such additives has not been followed by the development of any efficient technique of dosage that considers the strict requirements of an offshore platform.
In this paper, we describe a novel method of chemical dosage that takes into account all the on-site technical and practical parameters, such as the quantification thresholds or molecule specificity, the real-time monitoring, the resistance and compactness of measurement device and a user-friendly interface of measurement. Current techniques of inhibitor monitoring that use elemental analysis (ICP, MS, …) for sub-ppm quantifications appear too complex for a successful long-term on-site industrial exploitation due to the bulky dimensions of apparatus and the delay and complexity of analysis.
A long-term collaboration between University of Lyon and Total EP has defined a simple and accurate method for inhibitor monitoring based on the use of lanthanide tracers and the Time-Resolved Fluorescence (TRF) technique. We exploited the fact that inhibitor chemicals (i) are good chelators for lanthanide ions and (ii) amplify the luminescence signal of rare-earths. In this way we are able to collect the photon emission signal by TRF apparatus and dosing the inhibitors. The portability of the TRF device as well as the sensitivity of detection have been engineered in order to obtain a sub-ppm quantification threshold via 1-click task. Several carboxylates, phosphonates and sulphonates additives diluted in brine solutions has been easily measured out even in presence of residual oil. More than 20 commercial inhibitor solution samples were quickly prepared and dosed with an impressive linearity of response (R2 test &gt; 0.996) in the 10 – 100 ppm range. Any further extension of range has been possible. In addition, we were able to quantify two inhibitors (scale – scale, scale – corrosion) in the same brine water. This technique certainly opens a new conception of smart chemicals management in oil and gas production for (i) a dramatic minimization of the injected compounds (ii) a reducing delay in pipelines monitoring, and (iii) a shut down of expenses of pipeline maintenance.
Dissolution of Sulfide Scale: A Step Change With a Novel, High Performance, Non-Mineral Acid Chemical
Authors: Wylde Jonathan J. , Okocha Cyril , Smith Rashod , Mahmoudkhani Amir , Kelly Craig J. 
Published: April 2016

Abstract
Iron sulfide scale can be relatively common-place in maturing oil wells and produced water handling systems. Iron sulfide can also be commonly formed as a corrosion product, due to sour corrosion resulting from H2S containing fluids being processed through carbon steel tubulars. As more sour production is brought on-stream iron sulfide continues to become more prevalent. There are few options for removing deposits of iron sulfide scales especially when it comes to choice of chemistry. This paper discusses the most commonly performed techniques for iron sulfide removal, including hydrochloric acid, organic acids and THPS, and the varying degrees of success that these chemistries have in application. Challenges using hydrochloric acid are encountered due to the potentially high yield of H2S upon dissolution of the scale, along with FeCl2 and therefore the potential of secondary deposition.
This paper provides data on the development of a new dissolver for iron sulfide. Dissolver tests were performed initially on laboratory generated iron sulfide scale to optimize the formulation. Further testing was performed on different polymorphs of iron sulfide including pyrite, pyrrhotite, troilite, marcasite and mackinawite. Furthermore, several field scales were obtained and after XRD analysis, tested with the novel dissolver chemistry. It was shown that the new chemistry significantly outperformed THPS based dissolvers (active for active) and as well as 7.5% HCl. The corrosion rate of the novel chemistry was significantly lower than inhibited HCl and commercial THPS based blends. Testing was also performed at high pressure in order to understand the influence that pressure has on dissolution rates for all the commonly used dissolver chemicals. The new dissolver chemistry has significant chelating ability for sulfide scales as well as other ‘standard’ scale types including, calcium carbonate and calcium sulfate. The new product offers an effective multi-functional solution to dissolution of heterogeneous scale deposits.
The paper concludes with a case history of field application summarizing in detail the parameters of the field deployment and various KPIs used to measure success. The application is unusual as it was performed using a continuous injection method into an online system.
Development of Improved Chemical Formulations for Scale Control for Alkaline Surfactant Polymer Flood in a Seawater Flooded Reservoir
Authors: Bt Alwi Noraliza , Bt Salleh Intan Khalida , Ibrahim Jamal Mohamad , Carpenter Ian , Dyer Sarah J. , Simpson Caroline , Frigo Dario M. , Graham Gordon M. 
Published: April 2016

Abstract
Calcium carbonate scale control during Alkaline Surfactant Polymer (ASP) flooding is a recognised challenge due to mixing of the high-pH ASP waters with reservoir brine. In most cases ASP flooding is aimed towards reservoirs containing low-calcium and magnesium formation waters, and previous reports have concluded that in such cases production well scaling can be effectively treated with conventional scale inhibitors. For reservoirs containing moderate to high levels of alkaline-earth metal ions in the produced waters, such as reservoirs that have been flooded with sea water, the scaling risk is considerably exacerbated, with the result that conventional scale inhibitors are essentially ineffective except at very low sea-water fractions in the produced water mixture following ASP breakthrough.
This paper presents the results for an extensive research and development project firstly to examine alternative inhibitor chemistries and then to develop more complex formulations containing synergistic additives to improve calcium carbonate scale control in high sea-water content produced waters in ASP floods. The developed formulations are shown to control the scales effectively with water chemistries that were previously shown to be beyond the efficacy of conventional inhibitors (negligible effect at 500 mg/l).
The paper will present and discuss the different types of scale inhibitor chemistries examined, the nature of other chemistries and additives examined in combination with the scale inhibitors, and will describe the synergistic effects observed between the different chemicals.
Results from this extensive series of laboratory tests will then be presented showing the considerable benefits of the new formulations and demonstrating how scale inhibition can now be achieved under these extreme and previously uncontrollable producer well conditions. The paper will also introduce the challenges and present an overview of the case study that initiated this development program.
Predicting Calcite Scaling Risk Due to Dissolution and Re-Precipitation in Carbonate Reservoirs During CO2 Injection
Authors: Ribeiro Ayrton S. , Mackay Eric J. , Guimarães Leonardo 
Published: April 2016

Abstract
Carbonate reservoirs are more geochemically reactive than sandstones and can experience big changes in porosity and permeability because of mineral reactions. In this work, we analysed the calcite dissolution and precipitation in chalk reservoirs during injection of seawater and CO2 bearing fluids.
We performed reactive transport simulations with injection of seawater, carbonated water, CO2 gas, CO2 SWAG and CO2 WAG. We evaluated the mineral reactions that occur in the injector and producer blocks. Moreover, the calcite dissolution rate was calculated and its relationship with flow rate was investigated.
Simulation results showed that during injection of CO2 gas alone, calcite dissolution was fast but limited, and occurred everywhere. On the other hand, for the other injected fluids the dissolution around the injector was continuous and, with the exception of the seawater scenario, precipitation was observed downstream. In addition, the calcite dissolution per injected water pore volumes for both CO2 SWAG and CO2 WAG was higher because of higher dissolution of gaseous CO2 in injected and formation waters. Moreover, the dissolution rate was found to be proportional to the water flow rate which confirms the assumption that calcite kinetics are fast compared to reservoir flow.
This knowledge is valuable when planning CO2 WAG projects in carbonate reservoirs. As dissolution rates increase with flow rates, high permeability zones will show faster porosity changes, which may compromise the injector wellbore integrity and may lead to a more severe and growing calcite scaling risk around the producer wellbore.
Modelling Squeeze Treatments in Fractured Systems - A Case History
Authors: Kaur Amarpreet , Spooner Victoria E. , Frigo Dario M. , Stalker Robert , Graham Gordon M. , Jordan Myles M. 
Published: April 2016

Abstract
Scale inhibitor squeeze treatments in high-permeability sandstone reservoirs can be readily simulated using matrix flow models. However, designing such treatments for application in fractured shale reservoirs is less developed, partly because the mechanisms for fluid flow are less well understood and partly because the manner by which the inhibitors are transported and retained in fractured shale formations differ considerably from the simple matrix flow encountered in sandstone reservoirs.
Accurate prediction of squeeze treatment lifetimes is important for scale management both economically, to ensure optimum productivity at lowest cost of operation, and practically, to schedule treatments appropriately. Until recently this has not been achievable for fractured shale formations without the use of full-field simulators. This paper demonstrates that even a near-wellbore model, if appropriately modified, can achieve good agreement with inhibitor-returns field data from bullheaded squeeze treatments in 7 different multiply fractured wells in 2 different Unconventional shale formations.
Field data were compared with simulations using a model that couples inhibitor diffusion into and out of the rock matrix with adsorption either onto the rock matrix or the fracture proppant or both; it was found that in some field cases there is negligible difference between inclusion or exclusion of proppant adsorption, whereas in others much better simulation of inhibitor returns is observed if proppant adsorption is included.
Other aspects have been included in the model, such as the influence of proppant embedment (changing the porosity of the fracture void) and treatment of only a fraction of the multiple fractures present in a well. Interestingly, inhibitor returns in the 3 wells in one field correlated best with simulations assuming only a low fraction (up to 30%) of fractures were treated by the squeeze, whereas simulations from 4 wells in another field correlated better with a much higher fraction of fractures (60 – 90%) being treated.
This paper illustrates that an appropriate near-wellbore model can give good agreement with field data provided plausible physical phenomena are included, and that such a model can be used to design better squeeze treatments in Unconventional fractured-shale reservoirs without the need for complex full-field simulators.
Impact of Reservoir Temperature on Scale Inhibitor Retention - The Challenge of Ultra-Low Temperature Sandstone Reservoirs
Authors: Jordan M. M. , Johnston C. J , Sutherland L. 
Published: April 2016

Abstract
Control of inorganic scale within oilfield production wells via the scale squeeze process is well documented. The life time of the squeeze treatment is dictated by the cumulative volume of produced water flowing through the treated interval until the minimum inhibitor concentration (MIC) of the scale inhibitor is reached. Inhibitor chemicals with strong retention and low MIC values have been developed, deployed and for many years phosphonates and polymers containing phosphonate functional groups have been widely used.
This study looks at the issues faced by an operator with a low temperature sandstone reservoir of only 40°C and the challenges this low temperature brought which include high MIC for sulphate scale control and poor chemical retention & release observed during the reservoir condition corefloods. These findings will be compared and contrasted with two other higher temperature (71°C and 95°C) sandstone reservoirs where phosphonates and phosphate ester chemicals have been evaluated and deployed in the field.
The findings from this detailed coreflood study and review of previous experimental/field deployed scale squeeze treatment data shows that phosphonates work very well at elevated temperatures at and above 70°C where their stronger retention and excellent release profiles makes them a favoured chemical for such treatments, however at lower temperatures these molecules are not well retained on the rock and it is the phosphate ester chemicals that are more effective and provided the longer squeeze life. Comments on the interaction/performance of polymer scale inhibitors will also be made for these low temperature conditions
The implication of these findings clearly show that phosphate esters offer the potential for extended squeeze lifetime in the &lt;50°C sandstone reservoirs which are being developed in Northern Norway (Barents Sea) and the shallow depth, cool reservoirs being developed in offshore Brazil.
Using a Real-Time Visualisation Technique for the Assessment of Surface Scale Kinetics and Mechanisms of Inhibition
Authors: Sanni Olujide , Bukuaghangin Ogbemi , Charpentier Thibaut , Kapur Nikil , Neville Anne 
Published: April 2016

Abstract
Improving the understanding of surface scale formation is important in implementing an effective scale management strategy in the oil and gas industry. Investigations into scale formation have largely been focused on precipitation in the bulk solution by assuming that surface scaling always results from pre-precipitated crystals in the bulk solution. However, recent studies have shown that scale inhibition efficiency and the effects on crystal morphology vary between surface and bulk processes
The study is focused on the formation of BaSO4 and CaCO3 scale on stainless steel surface at constant saturation ratio (SR) using a visualization flow rig. The effects of SR, flow rates and temperature on surface scaling were studied. Also, the influence of SR and inhibitor concentration on surface inhibition efficiency of Polyphosphinocarboxylic acid (PPCA) and diethylenetriamine penta methylphosphonic acid (DETPMP) were studied. The range of SR considered is between 10 and 80 and with these values the experiments are conducted with no pre-precipitated crystals in the bulk solution. The flow rates used are between 10ml/min to 60ml/min.
It is shown that the determination of surface crystallization mechanisms and kinetics allows for the correct type and dosage of inhibitor to be selected. Addition of inhibitors at the bulk minimum inhibition concentration (MIC) actually aggravates surface scaling. For a similar range of SR and test conditions, CaCO3 scale builds up on the surface shows the predominance of growth which results in bigger crystals and a smaller number of crystals while BaSO4 scaling results in a higher number of crystals nucleating from the surface asperities with slower growth rate and hence smaller crystals.
Silica and Silicate Scale Formation and Control: Scale Modeling, Lab Testing, Scale Characterization, and Field Observation
Authors: Wang Wei , Wei Wei 
Published: April 2016

Abstract
We report an integrated study on silica and silicate scales in steam generator tube and water injection wells based on scale modeling and testing, scale sample characterization, and field observations.
For the steam generator tube scenario, significant amount of metal silicates in field scale sample were identified, which is consistent with the extremely high scaling potential indicated by scale modeling. Halite formation was not predicted by scale modeling but significant amount of halite was identified in the scale sampled from inside of a generator tube. It is suspected the formation of metal silicates, especially Fe silicates, can facilitate/accelerate the formation of other type of scales and eventually lead to the tube plugging, overheating, and failure.
For the injection well scale management study, silica and silicate were identified in the scale precipitates from waters sampled at upstream of the injection point. While scale modeling (based on the composition of the filtered water samples) indicates potential further metal silicate scale deposition at wellbore temperature and pressure conditions, no significant amount of metal silicate scale was identified in lab testing with current available field water samples. Lab testing shows the dominating scale for injection well is calcite, which appears consistent with learnings from an initial field trial testing.