bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling of Transport Properties Using the SAFT-VR Mie Equation of State
Authors: Gonzalez Alfonso , Pereira Luis , Paricaud Patrice , Coquelet Christophe , Chapoy Antonin 
Published: September 2015

Abstract
Carbon capture and storage (CCS) has been presented as one of the most promising methods to counterbalance the CO2 emissions from the combustion of fossil fuels. Density, viscosity and interfacial tension (IFT) are, among others properties, crucial for the safe and optimum transport and storage of CO2-rich steams and they play a key role in enhanced oil recovery (EOR) operations. Therefore, in the present work the capability of a new molecular based equation of state (EoS) to describe these properties was evaluated by comparing the model predictions against literature experimental data.
The EoS considered herein is based on an accurate statistical associating fluid theory with variable range interaction through Mie potentials (SAFT-VR Mie EoS). The EoS was used to describe the vapor-liquid equilibria (VLE) and the densities of selected mixtures. Phase equilibrium calculations are then used to estimate viscosity and interfacial tension values. The viscosity model considered is the TRAPP method using the single phase densities, calculated from the EoS. The IFT was evaluated by coupling this EoS with the density gradient theory of fluids interfaces (DGT). The DGT uses bulk phase properties from the mixture to readily estimate the density distribution of each component across the interface and predict interfacial tension values.
To assess the adequacy of the selected models, the modeling results were compared against experimental data of several CCVrich systems in a wide range of conditions from the literature. The evaluated systems include five binaries (CO2/O2, CO2/N2, CO2/Ar, CO2/n-C4 and CO2/n-C10) and two multicomponent mixtures (90%CO2 / 5%O2 / 2%Ar / 3%N2 and 90%CO2 / 6%n-C4 / 4%n-C10).
The modeling results showed low absolute average deviations to the experimental viscosity and IFT data from the literature, supporting the capabilities of the adopted models for describing thermophysical properties of CO2-rich systems.
Fly Ash Nanoparticle-Stabilized CO2-in-Water Foams for Gas Mobility Control Applications
Authors: Singh Robin , Gupta Abhay , Mohanty Kishore K. , Huh Chun , Lee Daeyang , Cho Heechan 
Published: September 2015

Abstract
The goal of this work is to develop a novel way of beneficially utilizing two main waste products from coal power-generation plants – carbon dioxide and fly ash – by generating fly ash nanoparticle-stabilized CO2 foam for CO2 EOR mobility control. First, as the grain size of fly ash is generally too large for injection into reservoirs, it was reduced to nano-size by the ball-milling process. Second, dispersion stability analysis was performed to evaluate a suitable dispersing agent for fly ash nanoparticles (FA-NP). A range of surfactants (anionic, cationic, and non-ionic) was used in dilute concentrations. Surfactants were screened based on particle-hydrodynamic diameters and polydispersity index of the dispersion as measured by dynamic light scattering. Third, foam flow experiments were performed using combinations of FA-NP and various surfactants. Aqueous foam was created in-situ by coinjecting the FA-NP and/or surfactants with liquid CO2 through a sandpack at a fixed foam quality. Foam texture, as seen in the view-cell, was used to screen suitable surfactants that stabilized strong foams. Finally, the foam flow experiments were conducted in a Berea sandstone core. Pressure drop across the core was measured to estimate the achieved foam resistance factor and the apparent viscosity of the generated foam. Nano-milling and thermal treatment processes were able to yield thermally-treated fly ash (TTFA) nanoparticles with an average size of 180 nm. Dispersion stability analysis revealed that anionic and non-ionic surfactants are suitable in dispersing these nanoparticles. Foam texture visualization demonstrated that strong carbon dioxide-in-water foam/emulsion with fine texture can be generated using TTFA nanoparticles in porous media in conjunction with a non-ionic surfactant or an anionic surfactant in dilute concentrations. Foam flow experiments in a Berea core showed that TTFA nanoparticles even in low concentrations (0.4 wt%) can significantly improve the foam stability and foam resistance factor of an anionic surfactant (in the absence of oil). Antagonistic effects were observed in foam stability in Berea core by addition of TTFA nanoparticles to nonionic surfactants. This study has the potential of not only to minimize the surfactant usage for foam-based CO2 EOR mobility control, but also to sequester both CO2 and fly ash in subsurface formations.
A New Analysis on the Convective Heat Transfer at the Edge of the SAGD Chamber
Authors: Li Qingmao , Chen Zhangxin 
Published: September 2015

Abstract
Heat transfer is an imperative mechanism in the SAGD (steam assisted gravity drainage) process for bitumen production. A better understanding of the heat transfer process is critical for a successful SAGD project design. Following the work of Butler (1981, 1985 and 1997), the conduction only assumption has been widely used. However, there have been some studies indicating the importance of convection heat transfer at the edge of a SAGD chamber.
Based on analysis of physical heat transfer mechanisms in the SAGD process, an improved analytical model is developed in this study to calculate the condensate velocity and heat transfer considering both conduction and convection. First, heat transfer at the edge of a steam chamber is analyzed to understand the role of condensate flow and steam chamber interface movement. Three possible cases are proposed to analyze the relationship between the energy left behind the front because of the steam chamber interface movement and the energy carried into the cold reservoir by the condensate flow in the SAGD process. Based on the heat balance analysis and available temperature-saturation relationship, a modified condensate velocity normal to the interface of a SAGD chamber is proposed. It is assumed that the condensate velocity is proportional to the steam chamber interface movement velocity, the fluid mobility ratio of reservoir to steam chamber interface, and the volume heat capacity ratio of reservoir to steam condensates. This new velocity is used to investigate the convection role in the heat transfer of the SAGD process. Moreover, heat transfer equations are solved by using constant heat flow (or Robin) boundary condition to verify the widely-used constant temperature (or Dirichlet) boundary condition at the edge of the steam chamber. The newly developed model is validated by calculating and comparing the condensate velocity normal to the interface, apparent thermal diffusivity and heat fluxes ahead of the steam chamber with filed data (Dover UTF Phase B, Athabasca Reservoir). It is shown that convection can provide a larger contribution to heat transfer than conduction at the edge of a steam chamber, but drops rapidly over a short distance normal to the interface. Considering a large convective heat flow at the edge of the SAGD chamber, temperature can be thought as a constant with minor error.
The developed theory provides a quick prediction of apparent thermal diffusivity, temperature distribution, heat fluxes considering both conduction and convection for the design of SAGD projects. Furthermore, it offers a simple formula to show connection between the condensate velocities normal to a chamber interface and the movement velocity of the chamber interface, which can be applied to any thermal processes with steam chamber expanding.
Fractured Volcanic Reservoir Characterization: A Case Study in the Deep Songliao Basin
Authors: Sun Desheng , Zhang Feng , Gao Jun , Xi Xiaoyu , Lin Jixiang 
Published: September 2015

Abstract
Based on the integrated acquisition and processing of 3D-VSP and full-azimuth surface seismic data, this paper focuses on the interpretation of volcanic reservoirs to characterize the fractured volcanic reservoir geometry, distribution, properties and highly productive gas regions.
The area of interest is located in the deep Songliao basin of north-eastern China. The area characterized by a monoclinal structure that includes a few fractured volcanic reservoir traps in Cretaceous formations. The P&D of gas reservoirs faced many difficulties, including imaging of the volcano, identification of heterogeneous volcanic rock facies, and fracture detection, which was the most important.
Use of seismic attributes for fractured volcanic reservoirs detection below the resolution of conventional seismic data is a major goal in this project. A method is developed to improve imaging of volcanoes, and minor faults and fractures using “discrete frequency curvature (DFC)”. The DFC data are computed using discrete frequency seismic data obtained from spectral decomposition. The DFC attribute allows us to recognize different geologic information about fractured volcanic reservoirs in different frequency bands of seismic data. The low-frequency curvature data can be used to recognize the distribution of volcanoes, whereas high-frequency curvature data is more effective at detecting minor faults and fractures. Moreover, the multi-geophysical methods, such as strata slice, HTI fracture detection and pre-stack inversion etc., also have been applied to characterize the volcanic reservoir. Strata time slices of coherence data are used to describe the volcanic evolution and volcanic rock facies. Structure modelling can provide an efficient tool to delineate geometry and distributions of volcanic bodies. The fracture inversion and HTI fracture detection method can be used to detect the orientation and density of fractured reservoir, while pre-stack inversion is applied to detect gas-bearing volcanic reservoirs.
After integrated study of the seismic attributes, well logs, and production data, we calculated porosity, permeability, net thickness and predicted the favourable production zones of the volcanic reservoir. The main factors controlling the volcanic reservoir are the distribution of volcanoes, volcanic rock facies, small faults, and fractures. The hydrocarbon reservoirs are located at a high position within the volcanoes, and the hydrocarbon is also clustered around the small faults and fractures within the system. Three horizontal wells were drilled based on the results of this study and very productive in the regions that were predicted to be enriched in hydrocarbons.
The results of our case study show DFC attribute has the potential to be a highly effective and very valuable seismic method.
Reservoir Rock Characterization Using Centrifuge and Nuclear Magnetic Resonance: A Laboratory Study of Middle Bakken Cores
Authors: Karimi Somayeh , Saidian Milad , Prasad Manika , Kazemi Hossein 
Published: September 2015

Abstract
In tight liquid-rich shale formations, fast and accurate techniques to determine reservoir key parameters, such as oil and water end-point saturations, capillary pressures, relative permeabilities, and pore-size distribution (PSD) are of great interest. In this paper, we use centrifuge and nuclear magnetic resonance (NMR) to determine these parameters for several Bakken cores. First, we measured helium porosity and Klinkenberg permeability of clean and dry Middle Bakken core plugs. After saturating these core plugs with brine, we performed drainage measurements using a high-speed centrifuge. Before and after centrifuge experiment, we measured the transverse relaxation time (T2) with a 2-MHz NMR instrument for use for pore-size distribution. Our results indicate that, using both centrifuge and NMR, we can obtain important petrophysical information for use in reservoir engineering and numerical simulation applications.
Improving Performance of the Phase Equilibrium Calculations in the Surface Network Portion of an Integrated Reservoir Simulator/Surface Network Compositional Model
Authors: Gu Zhiqiang , Wong Terry , Ma Jie 
Published: September 2015

Abstract
A network model can be extremely sophisticated for some miscible gas injection simulations. Sometimes, miscible gas injection, gas cap reinjection, and gas lift within the network are required to be solved simultaneously with a reservoir model. The phase equilibrium calculation for a network can consume a significant proportion of the total central processing unit (CPU) time. Equation of state (EOS) -based phase equilibrium can be divided into single-phase and two-phase calculations. Most research focuses on reducing the number and computational cost of EOS equilibrium calculations for reservoir modeling. Improving the performance of the phase equilibrium calculation for network flow is rarely discussed in the literature.
This paper describes methods applied to speed up the network calculations. The entire network is represented as a series of nodes and connections between nodes. It can be divided into several segments. If there is no introduction of other fluids from connecting segments, the overall composition is constant within a particular segment. Based on information from the previous phase status of each node or current phase status of up/downstream nodes, the nodes with a phase status change can be identified by regular single-phase stability analysis and flash calculation methods. Therefore, the segments can be divided into several single gas/oil and two-phase regions. For the nodes within two-phase regions, some correlation models can be applied to calculate equilibrium constant K-values for each component. Then, the flash calculation can be performed using the Rachford-Rice procedure. For single-phase regions, a phase envelope generation approach is used. A saturation pressure calculation is performed at a low value of pressure and temperature. Then, several points on the rest of the curve are extrapolated sequentially in a multistage extrapolation. If the temperature of a node is between two temperatures where an approximate value of the saturation pressure was identified, interpolation can be used to estimate the saturation pressure for this node.
A benchmark of example problems demonstrates that this approach can significantly speed up both single-phase stability tests and two-phase flash calculation with little accuracy loss. Phase equilibrium calculation is usually intensive in terms of CPU time. This paper designs a multistep procedure to identify the phase status along pipes. The improvement of computational efficiency in the phase equilibrium calculations within the surface network flow simulation can reduce the overall simulation CPU time and make it practical to run a full-field miscible gas injection model.
Effect of Large Capillary Pressure on Fluid Flow and Transport in Stress-sensitive Tight Oil Reservoirs
Authors: Xiong Yi , Winterfeld Phil , Wang Cong , Huang Zhaoqin , Wu Yu-Shu 
Published: September 2015

Abstract
The pore sizes of unconventional reservoir rock, such as shale and tight rock, are on the order of nanometers. The thermodynamic properties of in-situ hydrocarbon mixtures in such small pores are significantly different from those of fluids in bulk size, primarily due to effect of large capillary pressure. For example, it has been recognized that the phase envelop shifts and bubble-point pressure is suppressed in tight and shale oil reservoirs. On the other hand, the stress-dependency is pronounced in low permeability rocks. It has been observed that pore sizes, especially the sizes of pore-throats, are subject to decrease due to rock deformation induced by the fluid depletion from over-pressurized tight and shale reservoirs. This reduction on pore spaces again affects the capillary pressure and therefore thermodynamic properties of reservoir fluids. Thus it is necessary to model the effect of stress- dependent capillary pressure and rock deformation on tight and shale reservoirs.
In this paper, we propose and develop a multiphase, multidimensional compositional reservoir model to capture the effect of large capillary pressure on flow and transport in stress-sensitive unconventional reservoirs. The vapor-liquid equilibrium (VLE) calculation is performed with Peng-Robinson Equation of State (EOS), including the impact of capillary pressure on phase behavior and thermodynamic properties. The fluid flow is fully coupled with geomechanical model, which is derived from the thermo- poro-elasticity theory; mean normal stress as the stress variable is solved simultaneously with mass conservation equations. The finite-volume based numerical method, integrated finite difference method, is used for space discretization for both mass conservation and stress equations. The formulations are solved fully implicitly to assure the stability.
We use Eagle Ford tight oil formations as an example to demonstrate the effect of capillary pressure on VLE. It shows that the bubble-point pressure is suppressed within nano-pores, and fluid properties, such as oil density and viscosity, are influenced by the suppression due to more light components remained in liquid phase. In order to illustrate the effect of stress-dependent capillary pressure on tight oil flow and production, we perform numerical studies on Bakken tight oil reservoirs. The simulation results show that bubble-point suppression is exaggerated by effects of rock deformation, and capillary pressure on VLE also affects the reservoir pressure and effective stress. Therefore the interactive effects between capillary pressure and rock deformation are observed in numerical results. Finally, the production performance in the simulation examples demonstrates the large effect of large capillary pressure on estimated ultimate recovery (EUR) in stress-sensitive tight reservoirs.
Quantifying Electrical Resistivity of Isolated Kerogen from Organic-Rich Mudrocks using Laboratory Experiments
Authors: Firdaus Gama , Heidari Zoya 
Published: September 2015

Abstract
Reliability of conventional resistivity-porosity-saturation models (e.g., dual water and Waxman-Smits) is questionable in organic-rich mudrocks, which often leads to overestimation of water saturation. Previous publications showed that the interpretation of electrical resistivity logs for such rocks is challenging because of the presence of highly mature kerogen and pyrite connected networks that can influence electrical resistivity measurements. However, the electrical properties of kerogen in these rocks have not yet been quantified experimentally. Separation of kerogen from mudrocks and subsequent removal of pyrite from the kerogen, both requirements for successful laboratory experiments, remain challenging. In this paper, we quantitatively evaluate the electrical resistivity of mature kerogen using an experimental approach.
We first isolated kerogen from mudrock samples, using physical and chemical techniques and removed pyrite by treating the sample with acidic chromium chloride solution under nitrogen (N2) atmosphere. The isolated kerogen powder sample is then compressed to form a homogeneous consolidated disk using a mold frame designed for this purpose. Furthermore, we synthetically matured both mudrock and isolated kerogen samples by heat-treating. Then, we measured the electrical resistivity and geochemical properties of each set of molded samples at different maturity levels. The actual electrical resistivity of kerogen was estimated by minimizing the difference between the numerically simulated and measured effective electrical resistivity of the molded kerogen samples.
We successfully isolated kerogen from Haynesville and Eagle Ford mudrock samples. X-ray fluorescence (XRF) measurements confirmed the absence of carbonates, silicates, and pyrite in the isolated kerogen samples. We observed a significant decrease in electrical resistivity of isolated kerogen samples from the Haynesville (i.e., up to four orders of magnitude) and the Eagle Ford (i.e., up to nine orders of magnitude) formations upon elevating the heat-treatment temperature from 300°C to 800°C. The decrease of electrical resistivity at high maturity levels could be attributed to the presence graphite-like sheets and/or appearance of aromatic components in the organic matter. The outcomes of this paper can potentially improve interpretation of electrical resistivity logs in organic-rich mudrocks, which can lead to enhanced well-log-based assessment of in situ hydrocarbon saturation.
Nuclear Magnetic Resonance Investigation of Surface Relaxivity Modification by Paramagnetic Nanoparticles
Authors: Zhu Chunxiao , Daigle Hugh , Bryant Steven 
Published: September 2015

Abstract
Nuclear magnetic resonance (NMR) measurements are routinely used to characterize pore size distributions in fluid saturated porous media. The principle of the NMR measurement is that the result is linked with pore size by a parameter named surface relaxivity. However, in natural porous media, surface relaxivity is not constant or well-known due to heterogeneous distributions of impurities on pore surfaces. To control pore surface relaxivity, we injected paramagnetic zirconia nanoparticles into silica porous media: glass bead packs and sandstone core samples. Adsorption of the nanoparticles onto the pore surfaces altered their surface relaxivity due to differences in relaxivity between the silica surfaces and the nanoparticles. NMR measurements of porous media saturated with zirconia nanoparticle dispersions and deionized (DI) water were compared to calculate amount of adsorbed zirconia nanoparticles and quantify the alteration of pore surface relaxivity. Our results indicate that adsorption of nanoparticles onto pore surfaces leaves fewer nanoparticles in dispersion within the pore space and alters surface relaxation on pore wall with attached nanoparticles. The overall relaxation rate of the porous medium is thus affected by adsorption, which changes the surface relaxation rate and the relaxation rate of the fluid within the pore space. Electrostatic interactions drive nanoparticle adsorption onto pore walls. When silica porous media, which have negative surface charge, are saturated with positively charged nanoparticles, the nanoparticles adsorb onto the pore surface. When the porous media are saturated with negatively charged nanoparticles, no adsorption occurs. Our work highlights the importance of surface chemistry and adsorption on nanoparticle behavior in porous media and suggests that fundamental NMR behavior of media may be controlled with targeted adsorption of suitable nanoparticles.