bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiscale Simulation of Ion Migration for Battery Systems
Authors: Neuen Christian , Griebel Michael , Hamaekers Jan 
Published: April 2013

ABSTRACTIn this paper we describe a multi-scale approach to ion migration processes, which involves a bridging from the atomic scale to the macroscopic scale. To this end, the diffusion coefficient of a material i.e. a macroscopic physical quantity, will be appropriately determined from molecular dynamics simulations on the microscale. This way, performance predictions become possible prior to material synthesis. However, standard methods produce in general wrong results for ensemble setups which correspond to battery or capacitor applications.We introduce a novel method to derive correct values also for such problems. These values are then used in a macroscopic system of partial differential equation (Poisson-Nernst-Planck system) for the numerical simulation of ion migration in a battery.
Stability of Vanadium Electrolytes in the Vanadium Redox Flow Battery
Authors: Chuang Shu-Yuan , Leu Chih-Hsing , Hsueh Kan-Lin , Wu Chun-Hsing , Hsu Hsiao-Hsuan , Chen Yi-Ray , Chang Wen-Sheng 
Published: April 2013

ABSTRACTThe stability of the negative electrode electrolyte affects the efficiency and capacity of energy storage in the vanadium redox flow battery (VRFB) system. To explore the stability of vanadium electrolytes, the study prepared five types of V(II) electrolytes that were exposed to air in a fixed open area and monitored the charge state of vanadium ions over time by UV/Visible spectrophotometer. This study succeeded in preparing pure V(II) electrolytes. Five characteristics are found in the UV/Visible spectra, respectively, during the oxidation process from V(II) electrolytes to V(III) electrolytes and V(III) electrolytes to V(IV) electrolytes. The experimental results show that the oxidation rate of a solution of 1 M V(II) electrolytes to V(III) electrolytes and 1 M V(III) electrolytes to V(IV) electrolytes under an atmosphere of air is 4.79 and 0.0089 mol/h per square meter. The oxidation rates of 0.05-1 M V(II) electrolytes to V(III) electrolytes are approximately 96-538 times than that of V(III) electrolytes to V(IV) electrolytes.
Fabrication of Flexible and Conductive Graphene-Silver Films by Polymer Dispersion and Coating Method
Authors: Lin Jiang-Jen (JJ) , Shen Sheng-Yen , Shih Po-Ta , Dong Rui-Xuan 
Published: April 2013

ABSTRACTWe like to report a novel conductive film containing graphene-silver nanohybrids from the process of solution coating and annealing at low-temperature for melting silver nanoparticles (AgNPs) into interconnected Ag matrice on surface. The fabrication required the assistance of a home-made polymeric dispersant, poly(oxyethylene)-segmented imide (POE-imide), for homogenize the AgNPs and graphene in hybridized form. The intermediate dispersion of AgNPs at 10–25 nm diameter on the surface of 2D-graphene were characterized and subsequently subjected to solution coating into thin films. Under the annealing temperature as low as 160 °C, the films exhibited a high electric conductivity or low sheet resistance at 2.4×10–1 Ω/sq (equivalent to 7.9×104 S/cm). It is noteworthy that the significant point of low-temperature annealing at 160–170 °C that is attributed to the fast deterioration and degradation of the POE-imide organics kinetically before the AgNP coalescence and melting. Furthermore, the comparisons of using silicate clays and carbon nanotubes in replacing the 2D graphene for hybridizing Ag had revealed the different morphologies in Ag networks. The findings of using the polymeric dispersion for synthesizing nanohybrids may open up a new avenue for making films with integrated properties of flexibility, transparency and high conductivity for a host of electronic applications.
Room Temperature Ferromagnetism and Band Gap Engineering in Mg Doped ZnO RF/DC Sputtered Films
Authors: Mahadeva Sreekanth K. , Quan Zhi-Yong , Fan Jin-Cheng , Albargi Hasan B. , Gehring Gillian A , Riazanova Anastasia V. , Belova Lyubov M. , Rao K. V. 
Published: April 2013

ABSTRACTMg doped ZnO thin films were prepared by DC/RF magnetron co-sputtering in (Ar+O2) ambient conditions using metallic Mg and Zn targets. We present a comprehensive study of the effects of film thickness on the structural, optical and magnetic properties. Room temperature ferromagnetism was observed in the films and the saturation magnetization (MS) increases at first as the film’s thickness increases and then decreases. The MS value as high as ∼15.76 emu/cm3 was achieved for the Mg-doped ZnO film of thickness 120 nm. The optical band gap of the films determined to be in the range 3.42 to 3.52 eV.
An interview with Dr. Todd Deutsch on photocatalytic production of hydrogen
Authors: Kalkan A. Kaan 
Published: April 2013

For this themed issue of Nanomaterials and Energy (NME), we had the opportunity of conducting an interview with Dr. Todd G. Deutsch. Dr. Deutsch is a Senior Scientist in the Hydrogen Technologies & Systems Center at the National Renewable Energy Laboratory (NREL) in Golden, CO, USA. He has been a member of the Turner photoelectrochemical hydrogen production group at NREL since August 2006. He works on identifying and characterizing appropriate materials for generating hydrogen fuel from water using sunlight as the only energy input. Recently, his work has focused on ternary nitride materials grown by molecular beam epitaxy and corrosion remediation strategies for high-efficiency III–V photoelectrodes. In each of the past 6 years, he has been honored as an Outstanding Mentor by the US Department of Energy (DOE), Office of Science in recognition of his work as an advisor to over 25 students in the Science Undergraduate Laboratory Internship program at NREL.
Enhanced Swelling Effect and Viscosity Reduction of Solvent(s)/CO2/Heavy-Oil Systems
Authors: Li Huazhou , Zheng Sixu , Yang Daoyong 
Published: April 2013

SummaryIn this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with the addition of either solvent C3H8 or solvent n-C4H10. Experimentally, pressure/volume/temperature (PVT) tests are conducted to measure the saturation pressure, swelling factor, and viscosity of the C3H8/heavy-oil system, the C3H8/CO2/heavy-oil system, and the n-C4H10/CO2/heavy-oil system, respectively, in the overall temperature range of 280.45 to 391.55 K. It has been found that an increased swelling effect of heavy oil is obtained by adding the gas solvent C3H8 or n-C4H10 into the CO2 stream. An enhanced viscosity reduction of the CO2/heavy-oil system is also achieved in the presence of either C3H8 or n-C4H10. The enhanced swelling effect and viscosity reduction caused by adding either C3H8 or n-C4H10 into the CO2 stream are particularly favorable for achieving a higher heavy-oil recovery compared with pure-CO2 processes. Theoretically, three binary-interaction-parameter (BIP) correlations in the Peng-Robinson (PR) equation of state (EOS) (PR-EOS) method have been proposed for respectively characterizing CO2/heavy-oil binaries, C3H8/heavy-oil binaries, and n-C4H10/heavy-oil binaries by treating each oil sample as a single pseudocomponent with its molecular weight (MW) and specific gravity (SG). The BIP correlations (together with the PR-EOS) can be used to predict the saturation pressures and swelling factors of the C3H8/CO2/heavy-oil system and the n-C4H10/CO2/heavy-oil system with a generally good accuracy.
Analytical Study of Effects of Flow Rate, Capillarity, and Gravity on CO2/Brine Multiphase-Flow System in Horizontal Corefloods
Authors: Kuo Chia-Wei , Benson Sally M. 
Published: April 2013

Summary
This paper presents an approximate semianalytical solution for predicting the average steady-state saturation during multiphase coreflood experiments across a wide range of capillary and gravity numbers. Recently, the influences of flow rate, gravity, and subcore heterogeneity on brine displacement efficiency have been studied with the 3D simulator TOUGH2 (Kuo et al. 2010). These studies have demonstrated that the average saturation depends on the capillary and gravity numbers in a predictable way.
The purpose of this paper is to provide a simple and approximate semianalytical solution for predicting the average saturation (during two-phase coreflood experiments across a wide range of flow rates) for different average rock properties and fluid pairs. A 2D analysis of the governing equations for the multiphase-flow system at steady state is used to develop the approximate semianalytical solution. We have developed a new criterion to identify the viscous-dominated regime at the core scale. Variations of interfacial tension (IFT), core permeability, and length of the core and the effects of buoyancy, capillary, and viscous forces are all accounted for in the semianalytical solutions. We also have shown that three dimensionless numbers (NB, Ngv, Rl) and two critical gravity numbers (Ngv,c1, Ngv,c2) are required to properly capture the balance of viscous, gravity, and capillary forces. There is good agreement between the average saturations calculated from the 3D simulations and the analytical model. This new model can be used to design and interpret multiphase-flow coreflood experiments, gain better understanding of multiphase-flow displacement efficiency across a wide range of conditions and for different fluid pairs, and perhaps even provide a tool for studying the influence of subgrid-scale multiphase-flow phenomena on reservoir-scale simulations.
Microseismic Clouds: Modeling and Implications
Authors: Palmer Ian D. , Moschovidis Zissis A. , Schaefer Aaron 
Published: April 2013

Summary
Microseismic measurements provide qualitative information about the location of a fracture stimulation. However, there is also quantitative information to consider, a fact that has largely been neglected. We have developed a geomechanical model to predict the extent of shear failure during fracture stimulation of a well. The model identifies different types of failures, tensile and shear, which will occur on natural fractures or vertical planes of weakness. It is a “screening model,” meaning it takes a global perspective where point-by-point details of natural fracture distribution, fluid leakoff, and failure prediction are not emphasized. By matching the model to the extent of the microseismic cloud of shear failure, we obtain an injection permeability and porosity which characterize the volume of the microseismic cloud, which we assume to be a quasi-uniform fracture network with a system permeability enhancement. The model can be applied to any formation in which the microseismic distribution in each fracture stage is widespread, as happens in many tight shales (i.e., not elongated, as in a dominant vertical fracture).
From our modeling studies, a high injection permeability (&gt;100 md) is required to pressure the formation and achieve failure out as far as the microseismic events extend. Low injection porosity (&lt;0.1%) is required for the fracture fluid to leak off that far (this is typically much less than formation porosity of 3–5%). These numbers are symptomatic of fracture-controlled flow. Reports on interference with offset wells support this interpretation. As a case history, the method and results for sequential stimulation of two sister horizontal wells in the Barnett shale are described. The geomechanical model is matched to the composite cloud of all microseismic events measured in that well. Not all wells in a field have microseismic data, but the first few wells usually do, and modeling of these cases can provide useful directives for future wells. For example, the injection permeability can provide information on average fracture spacing and aperture width during injection, and these can be important for tailoring proppant size to acess the fracture network in gas and oil plays in tight shales.
Production Decline and Numerical Simulation Model Analysis of the Eagle Ford Shale Oil Play
Authors: Agboada Dieudonne K. , Ahmadi Mohabbat 
Published: April 2013

Abstract
Intrinsic behavior of fluid flow in extremely tight porous media and presence of hydraulically fractured long horizontal wells in shale oil reservoirs imposes different set of challenges for performance prediction. Conventional Arps’ prediction mechanisms are often inadequate to apply for two main reasons among others: transient flow regimes lasting the entire well productive life and short production history for young shales. Low hydrocarbon recovery factors also dominated the prospect. This paper compares and contrasts outcomes of some prediction mechanisms such as Arp's empirical equation in decline curve analysis (DCA), logistic growth analysis (LGA) of oil cumulative production, and numerical simulation model (NSM) analysis. Enhanced oil recovery (EOR) by injection of CO2 gas was also considered.
The study accomplishment is to recommend the most appropriate prediction tool that is applicable to hydraulically fractured horizontal wellbores in shale oil reservoirs dominated by transient flow regimes and having relatively short performance history. The outcome of the enhanced oil recovery simulation is significant to determine optimal spacing of producer-injector patterns and optimum drainage areas within and beyond the stimulated reservoir volumes (SRV).
Different outcomes were observed for the same well based on the sections or all of data analyzed using DCA. Logistic growth analysis of cumulative production forecasted conservatively similar to Arps’ exponential decline model. The logistic growth model fit quite well on most cumulative production trends especially at the ends of the profile leading to better predictions. Using realistic static and dynamic reservoir properties, NSM fits production histories very closely under constant operational settings, but the forecasted cumulative productions obtained are subjective to the accuracy of reservoir properties. Oil recovery factors from EOR slightly improved primary depletion values when the source reservoir was flooded with CO2 and could extend the well's productive life by 8–10 more years.
Process of shale oil performance prediction is not yet uniquely defined and calls for more investigation into diverse ways to perfect it. The options studied are useful in getting volumetric calculations closely accurate. Oil recovery optimization is also the heart of petroleum production, hence useful hint is provided.
All You Need is Darcy's Equation to Determine EOR Success or Failure
Authors: Farouq Ali S. M. 
Published: April 2013

Abstract
Enhanced Oil Recovery (EOR) has produced mixed results based on hundreds of field tests. Thermal recovery methods, notably steam injection, have been remarkably successful, whereas chemical flooding has not been commercially successful in the majority of the field tests. Miscible methods fall somewhere in between. It is shown that the performance of all of these methods can be explained in terms of Darcy's equation and the bank theory. Steam injection – cyclic, steamflooding, and steam-assisted gravity drainage (SAGD) – various versions of in situ combustion, polymer, surfactant, alkaline, ASP, micellar flooding, miscible processes, and carbon dioxide injection are systematically analyzed in terms of bank formation, if any, and Darcy's equation. The key variables are oil viscosity and relative permeability, with area being an important variable in gravity controlled processes. Oil production in all three phases – oleic, aqueous, and vapor – is considered. Bank theory is particularly useful when the initial oil saturation is close to immobile. In such a case, banking of the oil and water is governed by the initial saturations, as well as the respective saturations left behind and relative permeabilites. Related variables, such as well spacing, are also considered. Several examples are presented, and limits to enhanced oil production are noted.
Orcutt Oil Field Thermal Diatomite Case Study: Cyclic Steam Injection in the Careaga Lease, Santa Barbara County, California
Authors: Elias Ramon , Medizade Mason 
Published: April 2013

Abstract
Cyclic steam injection has been used in California since the 1960s. It has been used as a commercial technique to recover oil from diatomite since the mid-1990's. This paper is a synopsis of the analysis and interpretation of over three years of steam injection flow rate, pressure and temperature data from Santa Maria Energy's (SME) cyclic steam injection pilot project in the diatomite zone in the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field, Santa Barbara County, California.
The pilot consists of 19 cyclic steam injection wells configured in a 4x5 matrix spaced about 120 feet apart producing from a depth of about 925 feet. Operating practices are used specific to Careaga Lease geologic and reservoir features that include a tailored range of steam injection rates and steam volumes for each steam injection cycle. Comprehensive surveillance and steam injection management protocols are in place for maintaining a safe and reliable operation. The discussion that follows examines data gathered automatically at each well and their real time analyses.
Cycle-by-cycle analyses of steam injection and soak periods for all SME wells show (a) no indication of fractures being induced and (b) that large skin effects are present during steam injection in this project. The latter calls into question use of the tubing wellhead pressure as an indicator of the reservoir pressure while injecting steam.
Based on the analysis and interpretation of the data, it appears that mechanisms, such as differential thermal expansion of the heated rock and its fluids, are likely to be occurring within the geologic setting of this project to an extent not seen in more permeable rocks and could be favorably affecting the overall production response. Other possible effects are also cited.
Integration of Pressure Transient Data in Modeling Tengiz Field, Kazakhstan – A New Way to Characterize Fractured Reservoirs
Authors: Pan Yan , Hui Mun-Hong , Narr Wayne , King Gregory , Tankersley Terrell H. , Jenkins Steve D. , Flodin Eric A. , Bateman Philip W. , Laidlaw Chris , Vo Hai Xuan 
Published: April 2013

Abstract
Tengiz is a supergiant oil field with 30 billion STBOOIP located in the Pricaspian basin of western Kazakhstan. The field produces from an isolated carbonate platform of Devonian to Pennsylvanian age, with a flat-lying central platform surrounded by a relatively steep depositional slope. Fractures are common and significantly enhance productivity in the outer platform and slope. Understanding the flow behavior of the matrix-fracture system is a key to successful field development.
The characterization of naturally fractured reservoirs is especially challenging due to a high degree of heterogeneity and uncertainty. When modeling carbonate reservoirs – and particularly those where fractures play a significant role – we lack a consistent and robust methodology for utilizing dynamic data collected from pressure buildup tests, production logging, pulse tests between wells, and from increasingly deployed permanent down-hole gauges. Instead, this data, which contain rich information about wells and reservoir, is often neglected in the conventional production history matching. This project aims to fill this technology gap to better characterize fractured carbonate reservoirs. We apply numerical well testing techniques with discrete fracture modeling to understand and characterize the fracture-matrix properties. The effective utilization of pressure transient data should narrow the uncertainty, improve the characterization, and help optimize field development.
First the numerical solutions from both Discrete Fracture Models (DFM) and Dual-Porosity Models using numerical reservoir simulator were validated against analytical pressure-transient solutions for a dual-porosity system. Next a systematic workflow to integrate single-well buildup test data into numerical models was developed based on synthetic case study results. Finally the new method was applied successfully to a sector model of Tengiz field. Some preliminary techniques were also developed to honor pulse test data and analysis results between wells with numerical simulation models.
Continuous efforts are being made to improve field-scale reservoir simulation models using dynamic and static data of fracture-matrix systems for more accurate field performance forecast in Tengiz. The successful integration of all types of data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production from each well, and substantially increasing reserves.
History and Application of Resistance Electrical Heaters in Downhole Oil Field Applications
Authors: Sandberg Chet , Hale Arthur , Kovscek Anthony R. 
Published: April 2013

Abstract
Electrical heaters are seeing increased use in downhole applications. Low power heaters are used for viscosity flow assurance, paraffin buildup reduction and hydrate elimination. Electrical heating can be used where steam is not technically useful such as through permafrost, formations that are highly fractured with connectivity where SAGD is precluded and very deep wells with high pressure. Higher power electrical heating is now being use in formation stimulation for reduction of viscosity oil formations worldwide. The highest temperature applications are in the "Insitu Conversion Process" pioneered by Shell in the oil shale of Colorado. Polymer insulated heaters are used for temperatures under 400 °F and inorganic insulated heaters such as mineral insulated (MI) cable for temperatures as high as 1800 °F. The history of electrical heating applications and specific pilot results are reviewed. The paper reviews the technical characteristics of power source and temperature source electrical heaters. The paper reviews the history of electrical heater use in downhole applications, discusses the chemical, mechanical, and electrical challenges for downhole use and predicts the increased application of electrical heaters in the future. In South America there is a need for heaters as long as 7000 feet, operating at 4160 Volts with output of up to 350 watts per foot. The near well bore constraints of thermal diffusivity requiring a temperature source heater rather than a power source heater is discussed for use in Colorado Oil Shale applications. Process insitu time periods and energy balance for both conversion from Kerogen to bitumen; then upgrading the bitumen and to oil as light as 40 °API is also discussed. The time required for simple viscosity reduction heavy oil with suggested heater well spacing is reviewed.