bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reliability and validity of ICDAS II coding for occlusal caries using magnification: an in-vitro study
Authors: R. Sathyanarayanan , Usha Carounanidy , R. Sudhagar 
Published: May 2017

<p class="abstract"><strong>Background:</strong> <span lang="EN-IN">Pit and fissure caries presents diagnostic challenges due to its anatomical complexity and fluoride exposure. ICDAS II is a coding system for caries detection using clinical visual inspection. It identifies carious lesions by the change in colour, texture and surface integrity. Magnification might facilitate better detection of the lesions by enhancing the visual acuity. Thus, the objective of this study is to compare the reliability and validity of ICDAS II in detection of occlusal caries, with and without magnification, by using histological standard</span>.</p><p class="abstract"><strong>Methods:</strong> <span lang="EN-IN">This single blinded, randomized study included 334 unrestored extracted human premolars and molars. Two examiners independently scored pit and fissure caries status using ICDAS II criteria without magnification and later under 6 x magnification using surgical microscope. The samples were sectioned and lesions were scored using the ERK histological criteria, under Stereo microscope. The scores of the examiners were correlated with the histological scoring. Kappa statistics and Spearman correlation coefficients were performed. Optimal sensitivity, specificity of visual and enhanced visual examination was calculated by Receiver Operating Characteristic Curve (ROC). Likelihood ratios (LR) were also calculated. </span></p><p class="abstract"><strong>Results:</strong> <span lang="EN-IN">The kappa values for Inter examiner reproducibility of visual and enhanced visual examination under microscope were 0.638-0.694 and for histological examination it was 0.979. Intra examiner reproducibility for visual and enhanced visual examination was 0.665 – 0.594. There was a strong relationship between visual, enhanced visual and histological examinations. Spearman’s correlation coefficient of ICDAS-II visual and enhanced visual examination for each examiner, to ERK histological scores was 0.869-0.848. The sensitivity and LR+ for visual and enhanced visual examination was decreased as the ICDAS score was increased and specificity and LR- increased with increased ICDAS score</span>.</p><p class="abstract"><strong>Conclusions:</strong> <span lang="EN-IN">Reliability and validity of ICDAS scoring in detecting occlusal caries under magnification did not differ from clinical visual inspection</span><span lang="EN-IN">. </span></p>
Enhancing Optimization of Reservoir Simulation Processes in Next-Generation Reservoir Simulators
Authors: Temizel Cenk , Saputelli Luigi , Nabizadeh Mehdi , Balaji Karthik , Suhag Anuj , Ranjith Rahul , Wijaya Zein 
Published: May 2017

Abstract
In field development and management, optimization has turned out to be an integral component for decision-making. Optimization involves computationally intensive complex formulations but simplifies making decisions. For reaching the optimal solution to a defined objective function, optimization software can be combined with a numerical reservoir simulator. Hence, robust and faster results are imperative to optimization problems.
To maximize cumulative recovery and net present value (NPV), the reservoir simulator works on maximizing these predefined objective functions that can be multi-objective leading to Pareto sets with "trade-offs" between objectives. In optimization algorithms with predefined objective functions, there is a need for these objective functions to be flexible by using conditional statements through procedures, since generally they do not provide the flexibility required by the physical reservoir fluid flow phenomenon to "maneuver" throughout optimization iterations.
In this study, a commercial reservoir simulator is coupled with an optimization software. As the need was discuss earlier, conditional statements are implemented in the simulator as procedures. Operating the software/simulator combination under pseudo-dynamic objective functions is achieved through these procedures. Highest recovery for the time period mentioned in the conditional statement for the simulation is achieved by trying sets of combinations of parameters, which also makes the optimization process faster and more robust. Throught the use of these conditional statements, the procedures are able to implement piecewise objective functions as codes for a given time frame.
The objective function to be maximized by the optimization process in this study cumulative production. The optimized recoveries with pseudo-dynamic objective functions provide an enhanced recovery, as compared to that of an optimization case with predefined constant objective function in the optimization software throughout the iterations of the optimization and simulation process.
Numerical Modeling of Magnetic Nanoparticles Transport in a Two-Phase Flow in Porous Media
Authors: El-Amin Mohamed F. , Brahimi Tayeb 
Published: May 2017

Abstract
In this paper, the problem of magnetic nanoparticle injection into a water-oil two-phase flow under an external permanent magnetic field is investigated numerically. The mathematical model of the problem under consideration has been developed. We treat the water- nanoparticle suspension as a miscible mixture while it is immiscible with the oil phase. The magnetization, density, and viscosity of ferrofluids are obtained using immiscible mixture relations. On the other hand, the magnetized phase pressure will have additional pressure terms relative to the conventional thermodynamic pressure, namely, the ferrofluid phase dynamic pressure, the fluid magnetic pressure, and the magneto-strictive pressure, while, the magnetic normal pressure is neglected in this study. Physical variables including water-nanoparticle suspension saturation, nanoparticle concentration, and pore wall/throat deposited nanoparticle, are investigated under the influence of the magnetic field. From our results, we found that magnetic field has a significant effect on the physical quantities of the model. Therefore, a magnet can be implemented for enhanced oil recovery.
Sourceless Porosity-Density and Geomechanics with Logging-While-Drilling Tools in Carbonate Sequences
Authors: Chen Chao , Abd El-Aziz Sabry , Abdulkarim Anar , Aki Ahmet 
Published: May 2017

Abstract
Azimuthal acoustic logging-while-drilling (LWD) sensors have recently been used in a bottomhole assembly (BHA) to evaluate the viability of sourceless formation evaluation compared to conventional density-neutron data acquired in the same run in a horizontal well across a carbonate sequence.
Borehole deterioration and significant pore pressure variations across the reservoir layers pose wellbore stability risks during the drilling phase, which has historically requireddrilling deviated pilot-hole sections for evaluation purposes. These sections were then plugged, backed, and sidetracked.
Previous experiences in the same geological setting also encountered extreme borehole enlargements. LWD helped acquire high-quality data before borehole enlargement occurred. Additionally, possible rock anisotropy indications were observed, and rock mechanical moduli were derived. The results were then correlated and normalized to existing field geomechanics knowledge and offset well data.
Azimuthal acoustic tools, free of radioactive sources, were run in an LWD tool combination, with the primary objective of measuring porosity, pressure prediction, and possible anisotropy using a four-axis acoustic caliper sensor.
This paper discusses the planning, design, and execution of an LWD azimuthal acoustic tool in the case study well. Additionally, the viability, integrity, and robustness of logged data as well as interpreted results are discussed. Optimization of real-time drilling operations and petrophysical dataacquisition requirements are also investigated to help optimize future field development data-acquisition requirements and overall reservoirmanagement strategies.
Computational and Experimental Study of Microfracture Conductivity in the Eagle Ford Shale Using Microproppant Pillars
Authors: Madasu Srinath , Nguyen Philip D. 
Published: May 2017

Abstract
Proppant conductivity in fractures at closure is crucial to ultimate hydrocarbon recovery from reservoirs. The proppant distribution inside the fracture determines the conductivity. This paper presents the application of solids-free channel fracturing treatment in microfractures. Microproppant (MP) agglomeration forms mini-pillars that support the microfractures to help prevent their complete closure and to provide conductive flow paths. Mathematical modeling of the conductivity that results from the microproppant pillars is presented and compared with the experimental data for validation using split cores of an Eagle Ford shale outcrop sample. Proppant embedment caused by the fracture deformation is estimated using the numerical model.
This paper presents a new three-dimensional (3-D) mathematical model that couples the solids and produced-fluids fracture-flow fluid mechanics with the deformable proppant pillars. MP aggregates/pillars are modeled as deformable cylindrical agglomerates, and the particles are modeled as deformable aggregates that deform under the closure stress. The fluid flows inside the fracture when there is a pressure differential. The propped microfractures are modeled as deformable solids that interact with the fluid flow. The fracture deforms as a result of closure and fluid stress. The model captures the fracture and pillar deformations using moving-mesh capability.
Simulations of closure stress with multiple pressure differentials for flow through the solids-free channels were performed to compare the conductivity obtained from the experiments using the split Eagle Ford shale core. MP aggregates, with less supporting surface area, must support higher closure stress compared to the conventional packed-proppant fracture, which has higher stiffness and lower embedment. Core samples treated with MP droplets were tested to obtain the experimental conductivity data. The results showed that the MP aggregates provided better conductivity than the partial monolayer of MP particulates were uniformily distributed and the number of droplets was properly limited. This was validated both qualitatively and quantitatively during the experiments. An uncertainty analysis using the simulation model revealed that the MP aggregate height significantly influenced conductivity and, therefore, should be optimized to enhance production.
Application of the Superposition Principle for Pressure Build-Up Analysis at Variable Rates Compared with Horner's Method
Authors: Mohammed Akram F. 
Published: May 2017

Abstract
The pressure build-up equation derived by Horner is applicable to wells that produce at a constant rate. However, as a constant flow rate does not exist in practice, the Horner equation is not expected to yield accurate results. Because of this limitation, an alternative method must be used to account for a variable production-rate history. The principle of superposition enables the generation of pressure behavior solutions for variable-rate cases based on the constant-rate pressure behavior solutions. The superposition solution and its application in pressure build-up analysis are herein presented and are compared with the Horner method for different interpretation cases. Finally, the accuracy and reliability of the calculated results are discussed.
Analytical Solutions for Temperature Transient Analysis and Near Wellbore Damaged Zone Characterization
Authors: Mao Yilin , Zeidouni Mehdi 
Published: May 2017

Abstract
Productions from oil and gas reservoirs can induce significant pressure and temperature changes at the wellbore. The temperature signal is sensitive to reservoir properties and production parameters which can be very useful in characterizing the reservoir. In this work, we introduce novel analytical solutions to determine the temperature signal associated with theproduction of slightly-compressible hydrocarbon from a vertical well, and apply the solutions to the production from oil and gas reservoirs. Our procedures to obtain the analytical solutions from the governing equation involve making relevant assumptions that allow rigorous solutions to be constructed using Laplace transform. We extend the analytical solutions to include the near-wellbore damage, and to characterize the damaged zone.
Our results of the analytical models are benchmarked with those from a commercial numerical simulation software. We substantiate that the Joule-Thomson effect on the temperature profile is significant in near-wellbore region, and adiabatic expansion effect extends the radius of investigation of the transient temperature signal. The damaged zoneanalytical solution shows that damaged zone radius and permeability separately affect thetemperature transient signal. This isunlike the pressure transient response for which the effect of damage zone properties is lumped into a single parameter, i.e. the skin factor. The analytically derived equations for slopes of Joule-Thomson and adiabatic expansion effects in undamaged and damaged reservoir present very close agreement with those obtained numerically. We provide semi-log temperature interpretation techniques to determine the reservoir permeability and porosity, and damaged zone radius and permeability.
Dynamic Fractures in Tight Low-Permeability Oil Sandstone Reservoirs
Authors: Li Jiahong , Song Xinmin , Yu Tao , Hou Jianfeng , Lei Zhengdong 
Published: May 2017

Abstract
So far in China, unconventionally low-permeability oil sandstone resource has become the first contributor of proved reserve, and is occupying the most important section of oil production in near future. The low-permeability reservoirs have been primarily developed by waterflood, and therefore display a series of new and specific features. Among them, dynamic fracture, an important factor influencing waterflood performance, was studied in this paper.
This paper is a 5-step study of low-permeability oil sandstone reservoirs (average permeability between 0.3mD and 10mD) in Ordos basin, which is famous for its richness in low-permeability sandstone resources. First, dynamic fractures were identified by production data, injection profile, tracer monitoring and well test data. Secondly, mechanical experiment and discrete numerical simulation were integrated to analyze the forming mechanism of dynamic fractures. Third, remaining oil saturation observation of densely-spaced inspection well cores and unstructured-grid simulations were used in combination to obtain a 3-dimensional sweep scenario influenced by both dynamic fracture and matrix. Based on study above, the impact of dynamic fracture on waterflood was then analyzed. Finally, how to curb and use dynamic fractures to maximize recovery according to their different forming mechanisms were suggested.
The dynamic fracture is defined as fracture that reopen, propagate or close influenced by injection pressure. It can be identified by simultaneous features of drastic watercut increasing, sharp spike in GR curve of injection profile, fast breakthrough of tracer and high permeability anomaly by well test. Core sample mechanical experiment and theory calculation support dynamic fractures propagating on the basis of pre-existence fractures as the predominant forming mechanism. Fresh core observation of newly drilled inspection wells after 20y's waterflood indicates a higher percentage of vertical sweep by up to 30% in the direction of dynamic fracture than that perpendicular to the direction of dynamic fracture. Also dynamic fracture simulations show fast growth of dynamic fractures apparently narrows horizontal sweep and causes earlier drastic watercut increasing by years. A fast growing dynamic fracture deteriorates horizontal sweep, while dynamic fractures of a certain height increase vertical sweep. Moderate injection and stimulated fractures with enough height are conducive to enhance sweep and therefore recovery. If dynamic fractures connecting injectors and producers are unavoidable, a line injection pattern is then proposed.
This paper conducted a systematic study on dynamic fracture, which is a dominant feature and geological challenge for waterflood of unconventional tight oil sandstone reservoirs. It offers a guidance for future waterflood development of similar reservoirs.
Unlocking Billion Cubic Meter of Deep, Tight, Rich and Unconnected Gas Field
Authors: Marhoon Nadhal Al , Masroori Haitham AL , Abdul-Majid Imran , Ajayi Ayotunde , Sandoval Daniel , Khan Raees Ahmed , Qasmi Liali Al 
Published: May 2017

Abstract
The Tight Gas Reservoir (TGR) top structure is well defined in seismic data and can be interpreted across the entire area of North Oman. It is being identified as an extremely tight, disconnected, low porosity, low permeability and High Pressure – High Temperature (HPHT) reservoir, and thus presents unique challenges to harness its full production potential. Therefore, to optimise the subsurface location and ensure placing a successful well, the following approaches were implemented.
Firstly, full 3D geological model was generated to reproduce the reservoir heterogeneities and sedimentological behaviour of the TGR. Secondly, sweet spot identification techniques were used due to the heterogeneity nature of TGR properties in order to locate the optimum subsurface location. Lastly, a well completion strategy centred on hydraulically fractured cased-hole wells with immediate production to mitigate formation damage was implemented. This is achieved via abrasive jetting and thermal conductivity techniques to induce micro fractures that vastly enhanced the fracture efficiency, with velocity strings combined with depletion compression.
Furthermore, the characterization and simulation efforts are aimed to test the longevity of the wells in an Early Production System (EPS) to evaluate the optimal well count and spacing for the full Final Development Plan (FDP). Also, the interference between the wells in this tight formation has been studied. Data gathering activities encompasses formation evaluation logs, core analysis data and well test data.
The surface development concept is based on staged field development, with long term testing as the first milestone. EPS have been selected to provide long term production data gathering opportunity for assessing the reservoir and well performance behaviour in order to aid in defining the FDP.
This paper will highlight the success of unlocking tight, unconnected gas and describe methodologies applied to aid fully integrated subsurface loop development. Reservoir characterization, model creation and simulation challenges linked with the appraisal results will also be discussed.
A Numerical Study of Using Polymers to Improve the Gas Flooding in the Harweel Cluster
Authors: Hinai Nasser. M. , Saeedi A. , Wood Colin D. , Valdez R. 
Published: May 2017

Abstract
Field A, located within the Harweel cluster in southern Oman, has been recognised as a viable miscible gas injection candidate. However, the mobility ratio of such a flood is unfavourable due to the low viscosity of the injected gas (0.01 to 0.04 cP) as compared to that of the in-situ oil (0.24 cP). One approach to overcome this issue is to thicken the injected gas to effectively control the gas mobility and increase the sweep efficiency.
This study will present the details of a numerical reservoir simulation study, which assesses the potential benefits of adding polymers to the injected gas to increase the viscosity. Considering the composition of the AG in Field A, we have examined a number of different AG compositions to include different levels of hydrocarbon gas and CO2. We have also evaluated the direct effect of the different gas compositions on the oil properties during the flood.
The simulation was carried out using CMG-GEM and the associated PVT module CMG-WinProp. A full-field 3D geological model has been built based on the typical geological characteristics and the light oil fluid properties in Field A. The simulation model takes into account the reservoir heterogeneities and future design considerations of the enhanced oil recovery (EOR) project to be implemented in the field.
The results confirm that increasing the injected gas viscosity close to that of the oil has a significant effect on the gas mobility, time of breakthrough and the ultimate recovery in Field A. It has also been observed that the oil viscosity reduction with natural gas dissolution is much more pronounced than that achieved with the pure CO2. Such an effect resulted in 4% higher oil recovery by the injection of thickened natural gas (76%) than the thickened pure CO2 (72%). Furthermore, bacause gas breakthrough is delayed, a low gas-oil ratio can be maintained during the injection. These results demonstrate the real advantages of thickening the natural gas over CO2 for improving the gas flood efficiency in a light oil reservoir such as Field A.
The contribution of this study is significant considering the fact that to date there have been limited studies evaluating the effect of thickened natural gas for EOR. Most of the previously completed research work in this area have mainly focused on the identification of thickener polymers for CO2 injection processes.