bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiphase Flow in Fractures: Co-Current and Counter-Current Flow in a Fracture
Authors: Shad S. , Gates I.D. 
Published: March 2010

Abstract
Multiphase flow through fractures is important not only for naturally fractured petroleum reservoirs but also for underground disposal of radioactive waste and geothermal hydrotransport, cap rock integrity, as well as underground water and aquifer flow. For instance, naturally fractured reservoirs located in Northern Alberta contain large quantities of heavy oil and bitumen. It still remains unclear how multiple phases flow in fractures and how to determine the relative permeability of each phase that can be used in reservoir simulators. In typical practice, simulation of fractured reservoirs uses, in general, very crude and unproven hypotheses such as linear relative permeability curves. However, by using inaccurate relative permeability curves, large errors of the predicted oil recovery can result. In this work, a relatively simple flow model is derived to determine analytic functions for the relative permeability curves versus phase saturation in a single fracture. The results show that relative permeability is not just a function of the fluid saturations but also of the fluid properties and flow pattern within the fracture itself. The analysis reveals that at certain viscosity ratios and flow pattern conditions, the relative permeability of one phase can exceed unity owing to lubrication effects. The available experimental data confirms the validity of the proposed model.
Introduction
Fracture-dominated flow is not only important for naturally fractured petroleum reservoirs but also for underground disposal of radioactive waste, geothermal hydrotransport, cap rock integrity, and underground water and aquifer flow. In naturally fractured reservoirs, fractures are highly conductive flow pathways that dominate fluid transport throughout the reservoir. To examine flow of multiphase flow in fractures, many different experimental(1-12), theoretical(13-18) and numerical studies(19-26) have been done. However, flow structure and momentum transfer between flowing phases in fractures are not yet well understood(4, 27, 28). Transport parameters such as relative flow rates of phases and the relationship between fracture geometry and flow remain unclear. The relative permeability concept can be used to describe behaviour of multiple phases flowing together through porous media, interfering and aiding each other to move under the action of a pressure gradient. Despite the importance of relative permeability in fracture flows, still there is no unique and consistent theory which provides an easy, yet computationally inexpensive, method to calculate relative permeability curves in fractures.
Numerical Simulation and Sensitivity Analysis of Gas-Oil Gravity Drainage Process of Enhanced Oil Recovery
Authors: Jadhawar P.S. , Sarma H.K. 
Published: March 2010

Abstract
The oil recovery process is controlled by the rates of gas injection and oil production, relative permeabilities, reservoir heterogeneities and the balance among viscous, capillary and gravity forces. Crestal gas injection in horizontal, vertical or reef type oil reservoirs recovers significant volumes of the residual oil due to the gas-oil gravity drainage mechanism, indicating the significance of gravity forces. This study investigates the effects of the parameters that control the process (e.g., rate of the gas injection and oil production) and reservoir heterogeneities on the overall performance of immiscible gravity drainage enhanced oil recovery (EOR). Reservoir simulation studies are conducted to map effective combinations of these parameters with respect to the oil recovery performance.
Introduction
Gravity forces play an important role at nearly every stage of the producing life of the reservoir, whether it is primary depletion, secondary water or gas injection schemes or tertiary enhanced or improved oil recovery methods(1). They can be advantageously used to maximize oil recovery from the oil bearing zone under investigation through gravity drainage mechanism. Several cases reported in the literature suggest that it could deliver as high as 87 to 95% incremental oil recoveries in contrast to other gas injection EOR methods.
Gas-Oil Gravity Drainage Process
Gravity drainage is a process in which gravity acts as a main driving force and where gas replaces voidage volume(2). It is commonly implemented in either of the dipping or pinnacle reef type reservoirs.
CO2-assisted gravity drainage EOR process is a top-down process in which gas is injected in the gas cap through vertical wells at a rate lower than the critical rate (Figure 1). Critical rate is the rate at which injection gas fingers through oil zone (viscous instabilities) leading to its premature breakthrough at the production wells. Injected gas segregates and creates a gas-oil interface. Controlled oil production is started through horizontal wells placed at the bottom of the oil zone such that the voidage created by oil withdrawal (in addition to minor dissolved volumes) is replaced by the equivalent CO2 injection volume. When this happens, pressure differential across the gas cap and oil zone [that is gas-oil contact (GOC)] stay at or close to zero implying that the pressure in the gas zone behind the CO2 floodfront would be constant(3). This helps to maintain the reservoir pressure nearly constant.
Optimization of Production Performance in a CO2 Flooding Reservoir Under Uncertainty
Authors: Chen S. , Li H. , Yang D. 
Published: March 2010

Abstract
CO2 flooding has gained momentum in the oil and gas industry and might be suitable for approximately 80% of oil reservoirs worldwide based on the oil recovery criteria alone. In addition to miscibility, production performance needs to be optimized to achieve higher sweep efficiency and oil recovery. Although many techniques have been made available for production optimization in the upstream oil and gas industry, it is still a challenging task to optimize production performance in the presence of physical and/or financial uncertainties. In this paper, a new technique is developed to optimize production performance in a CO2 flooding reservoir under uncertainty. More specifically, potential uncertainties influencing production performance are analyzed and assessed by using the geostatistical technique. This enables us to integrate the available information within a unified and consistent framework and to generate multiple geological realizations accounting for uncertainty and spatial variability. Subsequently, the net present value (NPV) is selected as the objective function to be optimized by using the genetic algorithm, while well rates of the injectors and the flowing bottomhole pressure for the producers are chosen as the controlling variables. In addition, corresponding modifications have been made to accelerate the convergence speed of the genetic algorithm. A field case is used to demonstrate the procedures of the newly developed technique and the optimized results show that the oil recovery and the NPV can be increased by 6.4% and 9.2%, respectively. It is also found that the genetic algorithm is a powerful and reliable search method to optimize production performance of reservoirs with complex structures.
Introduction
CO2 flooding is considered as a promising and practical enhanced oil recovery (EOR) process because it not only increases oil recovery, but also reduces greenhouse gas emissions by sequestrating CO2 in the depleted reservoirs. In practice, CO2 flooding performance can be greatly affected by the reservoir heterogeneity, which can severely reduce the sweep efficiency, result in early CO2 breakthrough at the producers, and thus, leave a large amount of bypassed oil in the reservoir(1). Therefore, it is of fundamental and practical importance to optimize production performance of a CO2 flooding reservoir.
Impact of Uncertainty of Heavy Oil Fluid Property Measurements
Authors: Zabel F. , Law D.H.-S. , Taylor S. , Zuo J. 
Published: March 2010

Abstract
Heavy oil is particularly known for the difficulty it presents in obtaining accurate fluid property measurements. The uncertainty of heavy oil fluid property measurements affects the quality of fluid property data which in turn affecting the accuracy of production forecast. In our investigation, we included the impact from certain heavy oil fluid property uncertainties, including live oil viscosity and saturation pressure [or the initial gas-oil ratio (GOR)]. The reservoir simulations were performed for case studies with a 9°API reservoir fluid and geology similar to those typically found in the Faja region in Venezuela. Two base cases and the underlying process mechanisms were established, one assuming primary production process and one assuming steam-assisted gravity drainage process (SAGD). We then performed sensitivity studies of the different fluid property variations to determine the effect on the process performances. We found that the process mechanism dictated the magnitude of the sensitivity to different fluid properties. The uncertainties of the recovery prediction obtained from a reservoir simulator confirmed importance of selecting accurate fluid property data on the dynamic simulation prediction.
Introduction
In upfront reservoir engineering study, the reservoir and fluid properties are very important input data for the dynamic reservoir simulation as they dictate the accuracy of the simulation prediction. The uncertainties of the reservoir properties, such as the geologic and petrophysic data, are often given more attention than the uncertainties of the fluid properties, such as oil viscosity and initial GOR.
It is well known that there are uncertainties in fluid property data, especially for heavy oil, because accurate measurements of heavy oil properties are quite difficult to obtain. For example, it has been observed that a large variation exists in the heavy oil viscosity measured from different laboratories using different measuring techniques. In addition to the inconsistency from the measurements, fluid sampling is another main source contributing to the accuracy of fluid property data. Therefore, it is essential to study the effect of the variation in fluid properties, such as oil viscosity and oil saturated pressure (or initial GOR), to predict the heavy oil recovery performance by means of dynamic reservoir simulation.
Experimental and Numerical Study of Improving Heavy Oil Recovery by Alkaline Flooding in Sandpacks
Authors: Wang J. , Dong M. , Arhuoma M. 
Published: March 2010

Abstract
Chemical flooding has great potential for enhancing heavy oil recovery, especially for reservoirs where thermal methods are not feasible. It has been shown that the formation of emulsions during chemical flooding can effectively improve sweep efficiency and, consequently, increase heavy oil recovery. The mechanism of flow of oil-in-water (O/W) emulsion in porous media has been extensively studied and simulated using the filtration theory. Few studies have been done for the modelling of water-in-oil (W/O) emulsion flow in heavy oil reservoirs. This study experimentally investigated the effective viscosity of W/O emulsion in porous media. Alkaline flooding tests were performed in channelled sandpacks to demonstrate the effectiveness of sweep efficiency improvement by the in-situ produced W/O emulsions. High tertiary oil recoveries were obtained for all these tests. The alkaline flooding process was simulated by including the observed flow behaviour of extra resistance to water phase flow caused by the formation of W/O emulsions, as well as the adsorption of chemicals, interfacial tension reduction, and in-situ generation of W/O emulsions. These laboratory results and the developed simulation technique are proposed as an improvement to the simulation and design of the field-scale projects of chemical flooding for heavy oil recovery.
Introduction
Many heavy oil reservoirs in Western Canada are not suitable for steam injection techniques due to thin pay thickness. Both field and laboratory results demonstrate that waterflooding of heavy oil reservoirs can only achieve a very low oil recovery. The main causes for the poor sweep efficiency of waterflooding for these heavy oil reservoirs are very adverse mobility ratio, natural area and vertical reservoir heterogeneity and heterogeneity induced by primary production(1,2). Therefore, improving mobility ratio and blocking water flow through channels are essential for improving heavy oil recovery. The in-situ formation of emulsions during alkaline flooding has been recognized as one of the efficient methods to improve sweep efficiency for heavy oil recovery(3,4,5).
The effectiveness of alkaline flooding for acidic crudes was recognized as early as in the 1920s(6). Jennings et al.(3) proposed the mechanism of emulsification and entrapment for alkaline flooding. They carried out caustic flooding tests using a heavy oil. Their results showed that the in-situ produced O/W emulsions tended to plug water fingering and channels, resulting in improved sweep efficiency. Johnson(7) summarized possible mechanisms of alkaline flooding to improve oil recovery: dispersion and entrainment, wettability reversal, and emulsification and entrapment. The formation of W/O emulsions was also observed as a mechanism of improving oil recovery(8,9).
Migration as Trade Facilitation: Assessing the Links between International Trade and Migration
Authors: Hatzigeorgiou Andreas 
Published: March 2010

Abstract
The cost of international trade matters. As traditional barriers to trade continue to diminish in importance, additional ways to lower trade costs become increasingly important to promoting international trade. Migrants can help lower trade costs between their country of birth and their country of residence by providing an information channel that reduces friction and facilitates trade relations. This paper applies a gravity model to a large set of data about developed and developing countries to estimate the extent of the relationship between migrants and trade. The results suggest that both immigrants and emigrants are significantly related to higher trade volumes. Immigrants seem to be especially good at facilitating trade in differentiated goods, for which information costs are particularly important.
Effect of dielectric medium on angiotensin converting enzyme inhibitors binding to Zn2+
Authors: Šramko Martin , Šille Július , Ježko Pavol , Garaj Vladimír 
Published: March 2010

AbstractThe Becke3LYP density functional was used to study structural and thermodynamic parameters of bivalent zinc cation complexes with selected substrates and ACE inhibitors (H2O/OH−, neutral forms of captopril, zofenoprilat, omapatrilat, CH3CONHCH3, and N-terminal anions of captopril, zofenoprilat, omapatrilat, enalaprilat, perindoprilat, trandolaprilat, and fosinoprilat). The combination of DFT and the conductor-like polarizable continuum model (CPCM) were employed to compute the Gibbs interaction energies (ΔG) between Zn2+ and the selected ACE inhibitors for dielectric media with ɛ = 5 (to simulate the protein environment) and for water media (ɛ = 78.39) for comparison purposes. The results show that ΔG is sensitive to the dielectric constant of the environment and that lower dielectric medium favors the binding of inhibitors to the zinc cation.
Voltammetry of resazurin at a mercury electrode
Authors: Çakir Semiha , Arslan Emine 
Published: March 2010

AbstractElectrochemical behavior of resazurin on HMDE in Britton-Robinson (B-R) buffers (pH 2.0–10.0) was studied using the square-wave voltammetry (SWV), square-wave adsorptive stripping voltammetry (SWAdSV), and cyclic voltammetry (CV) techniques. The voltammogram of resazurin in B-R buffer at pH < 4.0 exhibited two cathodic reduction peaks. The voltammetric peaks were obtained at −0.144 V (reversible) and −1.250 V (irreversible) at pH 3.2, and correspond to the reduction of resorufin to dihydroresorufin and to the catalytic hydrogen wave, respectively. At pH > 4.0, a new irreversible cathodic reduction peak, assigned to the protonation of N-oxide on the phenoxazin ring, was observed. Electrochemical parameters (I p/E p, I p/v, I p/pH, I p/t acc) of the compound were determined. From the voltammetric data, electrochemical reduction mechanisms for all peaks have been suggested. Maximum peak current for the reversible peak was obtained at pH 4.1. A linear relationship between the current and concentration was determined, and also the lowest detection limit was found as 3.25 × 10−8 mol L−1 and 1.98 × 10−10 mol L−1 for SWV and SWAdSV, respectively.
Model predictive control of a CSTR: A hybrid modeling approach
Authors: Kvasnica Michal , Herceg Martin , Čirka Ľuboš , Fikar Miroslav 
Published: March 2010

AbstractThis paper presents a case study of model predictive control (MPC) applied to a continuous stirred tank reactor (CSTR). It is proposed to approximate nonlinear behavior of a plant by several local linear models, enabling a piecewise affine (PWA) description of the model used to predict and optimize future evolution of the reactor behavior. Main advantage of the PWA model over traditional approaches based on single linearization is a significant increase of model accuracy which leads to a better control quality. It is also illustrated that, by adopting the PWA modeling framework, MPC strategy can be implemented using significantly less computational power compared to nonlinear MPC setups.
A simple turbidimetric flow injection system for saccharin determination in sweetener products
Authors: Mendes Camila , Laignier Emiliane , Brigagão Maisa , Luccas Pedro , Tarley César 
Published: March 2010

AbstractA new method for saccharin determination in liquid sweetener products was developed. The method is based on the precipitation reaction of Ag(I) ions with saccharin in aqueous medium (pH 3.0), using a flow injection analysis system with merging zones, the suspension was stabilized with 5 g L−1 Triton X-100. All experimental parameters influencing the flow injection system were optimized by means of chemometric approaches. The linear analytical curve was built from 2.4 g L−1 up to 9.64 g L−1 (r = 0.9968) with a quantification limit of 2.40 g L−1. The precision assessed as relative standard deviation (n = 10) was found to be 1.75 % for the saccharin concentration of 7.20 g L−1. Based on interference studies performed with the substances commonly found in liquid sweeteners, such as sodium cyclamate, methylparaben, sodium aspartame, and benzoic and citric acids, at the analyte to interferent mole ratio of up to 1: 10, no interference with the saccharin determination was observed. The presence of chloride ions interferes with the method, but a preceding liquid-liquid saccharin extraction with ethyl acetate was successfully employed to overcome this drawback. Accuracy of the method in sweetener products was evaluated by a comparison with the HPLC method.
Synthesis, spectral and electrochemical study of coordination molecules Cu4OX6L4: 4-cyanopyridine Cu4OBrnCl(6−n)(4-CNpy)4 complexes
Authors: Ondrejovič Gregor , Kotočová Adela , Koman Marian , Segľa Peter 
Published: March 2010

AbstractNew 4-cyanopyridine halide and mixed-halide Cu4OBrnCl(6−n)(4-CNpy)4 complexes (4-CNpy = 4-cyanopyridine, n = 0–6) were synthesised, characterised, and studied by infrared spectra, electronic spectra, and cyclic voltammetry. Infrared spectra revealed donor-acceptor vibrational couplings of the Cu4O, Cu-Cl, and Cu-N stretching vibrations with the in-plane and out-of-plane pyridine ring vibrations. The infrared spectra, electronic spectra, and half-wave potentials correspond to a weak donor and a strong acceptor behaviour of the 4-cyanopyridine ligands and to π-back bonding, Cu(II)→pyridine rings. The results were compared with the related pyridine and 4-substituted pyridine complexes.
Analysis of diagnostic confidence: Application to data from a prospective randomized controlled trial of CT for acute abdominal pain
Authors: Ng Chaan S. , Palmer Christopher R. 
Published: March 2010

Background: Changes in diagnostic confidence are used as a measure of a test's efficacy. There are several methods for analyzing such data, but it is unclear which are most robust. Purpose: To compare analytical methods for assessing diagnostic confidence, applied to data from a prospective study of computed tomography (CT) for acute abdominal pain. Material and Methods: Changes in diagnostic confidence in an illustrative case study were evaluated using five methods: “Basic,” “Retained diagnosis,” “Omary,” “Tsushima,” and “Score-based.” The case study was a randomized controlled trial of patients admitted to hospital for acute abdominal pain for whom immediate CT was not indicated, comparing “early” CT undertaken within 24 h of admission versus routine standard practice. Admitting surgeons recorded their diagnoses and confidences (5-point scale, 10–90%) both on admission and after 24 h. One- and two-sample t tests, and intention-to-treat and as-treated analyzes, were performed using all five analytic methods. Results: In the case study, 118 patients were randomized to early CT ( n=55) or standard practice ( n=63). Mean (SD) diagnostic confidence increased between the two time points by 20.7 (25.2)% and 13.0 (24.9)%, respectively. Early CT showed increases in diagnostic confidence by all one-sample analyzes (all P<0.055). Compared with standard practice, early CT showed significant increases in diagnostic confidence on an a) as-treated basis when using Basic, Omary and Score-based analyzes ( P<0.045), but not by the other two analytic methods, and b) intention-to-treat, only by Omary analysis. Conclusion: The method of analysis used to evaluate diagnostic confidence can influence conclusions about a test's efficacy. Methods incorporating the soundest analytical principles are recommended.
Differentiation between grade 3 and grade 4 articular cartilage defects of the knee: Fat-suppressed proton density-weighted versus fat-suppressed three-dimensional gradient-echo MRI
Authors: Lee So Yeon , Jee Won-Hee , Kim Sun Ki , Koh In-Jun , Kim Jung-Man 
Published: March 2010

Background: Fat-suppressed (FS) proton density (PD)-weighted magnetic resonance imaging (MRI) and FS three-dimensional (3D) gradient-echo imaging such as spoiled gradient-recalled (SPGR) sequence have been established as accurate methods for detecting articular cartilage defects. Purpose: To retrospectively compare the diagnostic efficacy between FS PD-weighted and FS 3D gradient-echo MRI for differentiating between grade 3 and grade 4 cartilage defects of the knee with arthroscopy as the standard of reference. Material and Methods: Twenty-one patients who had grade 3 or 4 cartilage defects in medial femoral condyle at arthroscopy and knee MRI were included in this study: grade 3, >50% cartilage defects; grade 4, full thickness cartilage defects exposed to the bone. Sagittal FS PD-weighted MR images and FS 3D gradient-echo images with 1.5 T MR images were independently graded for the cartilage abnormalities of medial femoral condyle by two musculoskeletal radiologists. Statistical analysis was performed by Fisher's exact test. Inter-observer agreement in grading of cartilage was assessed using κ coefficients. Results: Arthroscopy revealed grade 3 defects in 17 patients and grade 4 defects in 4 patients in medial femoral condyles. For FS 3D gradient-echo images grade 3 defects were graded as grade 3 ( n=15) and grade 4 ( n=2), and all grade 4 defects ( n=4) were correctly graded. However, for FS PD-weighted MR images all grade 3 defects were misinterpreted as grade 1 ( n=1) and grade 4 ( n=16), whereas all grade 4 defects ( n=4) were correctly graded. FS 3D gradient-echo MRI could differentiate grade 3 from grade 4 defects ( P=0.003), whereas FS PD-weighted imaging could not ( P=1.0). Inter-observer agreement was substantial (κ=0.70) for grading of cartilage using FS PD-weighted imaging, whereas it was moderate (κ=0.46) using FS 3D gradient-echo imaging. Conclusion: FS 3D gradient-echo MRI is more helpful for differentiating between grade 3 and grade 4 cartilage defects than is FS PD-weighted imaging.