bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Multiple Mixing-Cell Method to Improve Speed and Robustness of Compositional Simulation
Authors: Rezaveisi Mohsen , Johns Russell T. , Sepehrnoori Kamy 
Published: June 2014

Abstract
Standard EOS-based phase equilibrium modeling in reservoir simulators involves computationally intensive and time-consuming iterative calculations for stability analysis and flash calculations. Therefore, speeding up stability analysis and flash calculations and improving robustness of the calculations are of utmost importance in compositional reservoir simulation.
Prior knowledge of the tie lines traversed by the solution of a gas injection problem translates into valuable information with significant implications for speed and robustness of reservoir simulators. The solution of actual gas injection processes follows a very complex route due to dispersion, pressure variations, and multi-dimensional flow. The multiple mixing-cell (MMC) method originally developed to calculate minimum miscibility pressure of a gas injection process, accounts for various levels of mixing of the injected gas and initial oil. This observation suggests that the MMC tie lines developed upon repeated contacts may represent a significant fraction of the actual simulation tie lines encountered. We investigate this idea and use three tie-line-based K-value simulation methods for application of MMC tie lines in reservoir simulation. In two of the tie-line-based K-value simulation methods, we examine tabulation and interpolation of MMC tie lines in a framework similar to the compositional space adaptive tabulation (CSAT). In the third method, we perform K-value simulations based on inverse distance interpolation of K values from MMC tie lines.
We demonstrate that for the displacements examined the MMC tie lines are sufficiently close to the actual simulation tie lines and provide excellent coverage of the simulation compositional route. The MMC-based methods are then compared to the computational time using other methods of phase equilibrium calculations including a modified application of CSAT (an adaptive tie-line-based K-value simulation), a method utilizing only heuristic techniques, and the standard method in an IMPEC-type (implicit pressure, explicit concentration) reservoir simulator. The results show that tabulation and interpolation of MMC tie lines significantly improves phase equilibrium and computational time compared to the standard approach with acceptable accuracy. The results also show that computational performance of the MMC-based methods with only prior tieline tables are very close to that of CSAT, which requires flash calculations during simulation. The K-value simulations using MMC-based tie-line interpolation methods improve the total computational time up to 51% in the cases studied with acceptable accuracy.
The results suggest that MMC tie lines represent a significant fraction of the actual tie lines during simulation and can be used to significantly improve speed and robustness of phase equilibrium calculations in reservoir simulators.
The Effect of Cr(III) Acetate-HPAM Gel Maturity on Washout from Open Fractures
Authors: Brattekås Bergit , Pedersen Stina G. , Nistov Hilde T. , Haugen Åsmund , Graue Arne , Liang Jenn-Tai , Seright Randall S. 
Published: June 2014

Abstract
The blockage performance of a Cr(III) acetate-HPAM gel was investigated using several different application regimes and gel maturities. Fractured core plugs from four outcrop core materials were used, all constituting smooth, longitudinal fractures of 1 mm aperture. Mature and immature gel was placed in the fractures, and for some application regimes in the surrounding core matrix, and the blockage performance assessed by recording rupture pressures and subsequent residual resistance factors during chase waterfloods, Frrw. Placement of mature gel in open fractures yielded consistent rupture pressures during subsequent water injections, following linear trends for given gel placement rates and throughput volumes. The rupture pressures were predictable and stable in all the core materials studied. Rupture pressures achieved after placement and in-situ crosslinking of gelant were comparable to mature gel rupture pressures, but were less predictable. When maximizing gelant saturation in the matrix, rupture pressures were measured to 12 – 53 psi/ft. The maximum achieved rupture pressure when gelant was placed without matrix taps to promote leakoff was 11.9 psi/ft. Interactions between rock material and gelant were observed when Bentheim sandstone cores were used, and gel was in some cases not formed. No such interactions were observed in experiments using formed gel. Significant permeability reduction for water was achieved when both gel and gelant were used. Residual resistance factors for cores treated with gel and gelant were initially comparable. After eight water flushes (&gt;120 fracture volumes (FV) water injected) substantially greater pressure gradients were observed in cores treated with formed gel rather than gelant cross-linked in-situ and the permeability reduction averaged a factor 5000 for gel and 600 for gelant treated cores. The significance of these observations to field applications will be discussed.
A Methodological Analysis of the Mechanisms Associated to Steam-Solvent Co-Injection Processes Using Dynamic Gridding
Authors: Perez-Perez A. , Mujica M. , Bogdanov I. , Hy-Billiot J. 
Published: June 2014

Abstract
Hybrid steam-solvent processes have gained importance as a thermal recovery process for heavy oils in recent years. A number of pilot projects during the last decade indicates the increasing interest in this technology. Steam-solvent co-injection process aims to accelerate oil production, increase ultimate oil recovery, reduce energy and water disposal requirements and diminish the volume of emitted greenhouse gases compared to the steam-assisted gravity drainage (SAGD) process. Among the identified physical mechanisms that play a role during the hybrid steam-solvent processes are the heat transfer phenomena, the gravity drainage and viscous flow, the solvent mass transfer and the mass diffusion/dispersion phenomena. The major consequence of this complex interplay is the improvement of oil phase mobility which is controlled by the reduction in the oil phase viscosity at the edge of the steam chamber. It follows that a detailed representation of this narrow zone is necessary to capture the involved physical phenomena.
In this work, a study of sensitivity to grid size was carried out to define the appropriate grid necessary to represent the near-edge zone of the steam-solvent chamber. Our results for the steam-solvent co-injection process indicate that a decimetric scale is required to represent with a good precision the heat and mass transfer processes taking place at the edge of the steam chamber. In addition, we present some numerical results of the adaptive dynamic gridding application. Comparison was done between the SAGD process and steam-solvent co-injection after the characterization and analysis of the mechanisms which govern the oil production under the typical Athabasca oil sand conditions. Finally, in the framework of the proposed numerical methodology the effect of solvent type and injection conditions on the oil recovery efficiency is quantitatively illustrated. Published data for similar applications are also discussed.
It is expected that this work will provide some insight to the simulation community about methodological aspects to be taken into account when hybrid steam-solvent processes would be modeled.
Correlation of Pure Water Saturation Properties by Equations of State Using the Association Concept
Authors: Forouzanfar F. , Pires A. P. , Reynolds A. C. 
Published: June 2014

Abstract
Modeling of enhanced / improved oil recovery processes that takes into account mass transfer between phases depends on the correct prediction of thermodynamic properties and composition of phases in equilibrium. In a steam flood process, the mutual water / hydrocarbons solubility is a function of the temperature, pressure and fluid composition of the system and may not be negligible at flooding conditions. The most used equations of state (EoS) in the petroleum industry fail to accurately correlate saturation properties of polar substances that self-associate through hydrogen bonding and as a consequence, do not calculate the distribution of the components among equilibrium phases precisely. In this paper, we present the development of the Association Peng-Robinson and Association Soave-Redlich-Kwong equations of state. The proposed equations of state are composed of two parts, one physical (the original cubic equation of state model) and one chemical (an empirical chemical reaction term which accounts for the self-association of a component) and can be used to model systems in equilibrium that contain one associating component such as water or alcohol. In the extended equations of state which includes the self-association chemical reaction, the degree of the molar volume polynomial is increased from its normal value of three to six but, in general, there are only three positive roots. The chemical part of the extended EoS includes three parameters that can be adjusted to match data, the entropy and enthalpy of the association chemical reaction and one free parameter. The fugacity calculations for the extended EoS can be split into physical and chemical parts, where the physical part has exactly the same form as the original equation of state fugacities. In order to estimate the new parameters of the proposed equations of state, the differences between the experimental and calculated saturation pressure and saturated liquid molar volume of pure water are minimized using a Particle Swarm Optimization (PSO) algorithm. The equations of state presented here enhance the original ones through the addition of a chemical part to deal with self-associating polar components. The average relative deviation between the experimental and calculated saturated data using the association forms of the Peng-Robinson and Soave-Redlich-Kwong equations of state are smaller than those obtained from the original models. The chemical reaction approach is robust and improves the prediction of thermodynamic equilibrium properties of self-associating pure components by adding only three adjustable parameters, where two of them have a clear physical meaning (self-associating reaction enthalpy and entropy).
Three-Phase Relative Permeabilities as a Function of Flow History
Authors: Kianinejad A. , Aminzadeh B. , Chen X. , DiCarlo D. A. 
Published: June 2014

Abstract
Three-phase relative permeability is one of the main parameters in flow predictions of tertiary recovery processes in petroleum reservoirs. In particular, an understanding of the hysteresis in three phase relative permeability is essential to describe cyclic processes such as water alternating gas (WAG) injection. Several studies measured three-phase relative permeabilities through steady-state and unsteady-state indirect methods, with their own advantage and disadvantages. Among these, unsteady-state direct measurements are preferred since they mimic the natural reservoir processes while no assumptions are made for relative permeability calculations. But, previous unsteady-state direct measurements of three-phase relative permeability obtained relative permeabilities only during drainage processes. In this work, we extend this method to directly obtain oil and water relative permeabilities during three-phase flow through different flow cycles. The method involves in-situ measurements of phase saturation, and a combination of applied gas and water flow to overcome the limitations of previous direct relative permeability measurements. This method is used to directly measure the three-phase hysteresis effects in relative permeability. Specifically, we perform flow experiments in a 3ft long, vertically oriented sand pack; the sand pack is initialized at a specific oil saturation using two-phase flow. As opposed to previous unsteady-state direct measurements of three-phase permeabilities, gas and water are injected separately as different cycles and, the saturation along the sand pack is measured at different times using computerized tomography scanning. The relative permeability of each phase is then obtained directly from the measured in-situ saturations using Darcy's law. The results show that, we should pick only the middle 40cm of the saturation data to avoid the effect of capillary entry and capillary end effects on saturation data. Experimentally, we find that, the oil relative permeability rises at the beginning of each WAG cycle and then decreases almost as abruptly, with very little dependence on the phase saturations. On the other hand, the water relative permeability remains almost constant. The results also show that, the residual oil saturation decreases during the WAG process at different cycles. The results are discussed in terms of local flow processes, and potential implications for reservoir flooding are given.
Low Salinity Water Flooding: Effect Of Crude Oil Composition
Authors: Fjelde Ingebret , Omekeh Aruoture Voke , Sokama-Neuyam Yen Adams 
Published: June 2014

Abstract
Reduction of the salinity of injection water has been found to improve the oil recovery in some sandstone reservoir rocks, but for other sandstone rocks disappointing results have been obtained. No mechanism has been widely accepted as the reason for the improved oil recovery in low salinity water flooding (LSWF). Since alteration of wettability to more water-wet conditions has been reported in promising cases, desorption of crude oil components from the minerals surfaces should occur during LSWF. Retention of oil components onto sandstone reservoir rock saturated with brines of different compositions has been studied by injecting crude oils of different compositions. Results from experiments and simulation of rock-brine interactions have been compared.
In the study it has been shown that the compositions of both low salinity water and the crude oil are important for the retention of polar oil components. For the original crude oil with the lowest base/acid ratio, the retention of oil components was found to vary with the brine composition even though the total salinity was the same. For this crude oil the measured decrease in the retention of oil components was found to be in accordance with simulated decrease in the total concentration of divalent cations on clay surfaces. This indicated that the retention of oil components were dominated by bonding of carboxylic groups to clay surfaces by cation-bridging. For treated crude oil with reduced amount of acidic components (highest base/acid ratio), the retention of polar oil components was not sensitive to the brine salinity/composition and was higher than for the original oil (with lowest base/acid ratio). The retention was for this oil probably due to direct adsorption of basic components. The retention was therefore found to be sensitive to the concentration of acids in the crude oil, and was increasing with increasing base/acid ratio.
It has been shown the ionic composition of the low salinity brine and the composition of the crude oil are important for the retention of polar oil components and thereby the wettability. The optimum low salinity water composition will depend on the formation water composition, mineral composition/distribution of reservoir rock and oil composition, and for tertiary LSWF also the composition of earlier injection brine.
A Mechanistic Integrated Geochemical and Chemical Flooding Tool for Alkaline/Surfactant/Polymer Floods
Authors: Korrani Aboulghasem Kazemi , Sepehrnoori Kamy , Delshad Mojdeh 
Published: June 2014

Abstract
Mechanistic simulation of alkaline/surfactant/polymer (ASP) flooding considers chemical reactions between the alkali and the oil to form in-situ soap and reactions between the alkali and the minerals and brine. A comprehensive mechanistic modeling of such process remains a challenge, mainly due to the complicated ASP phase behavior and the complexity of geochemical reactions that occur in the reservoir. Due to the lack of the microemulsion phase and/or lack of reactions that may lead to the consumption of alkali and resulting lag in the pH, a simplified ASP phase behavior is often used.
UTCHEM-IPhreeqc, a previously developed robust, accurate, and flexible integrated tool at the University of Texas at Austin (UT), is further expanded to mechanistically model ASP floods. UTCHEM has a comprehensive three-phase (water, oil, microemulsion) phase behavior model for the mixture of surfactant and soap as a function of salinity, temperature, and co-solvent concentration. IPhreeqc, a state-of-the-art geochemical package of the United States Geological Survey (USGS), handles the geochemical reactions involved between crude oil, rock, and brine.
Through this integrated tool, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, surface complexation, and ion-exchange reactions under non-isothermal, non-isobaric, and both local-equilibrium and kinetic conditions. IPhreeqc has rich databases of chemical species and also the flexibility to define the alkali reactions required for the ASP modeling. Hence, to the best of our knowledge, for the first time, the important aspects of ASP flooding are considered.
The expanded integrated tool, UTCHEM-IPhreeqc, is then used to match three different reaction-related chemical flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a non-acidic crude oil, and alkaline/co-solvent/polymer (ACP) flooding.
Is Wettability Alteration the Main Cause for Enhanced Recovery in Low-Salinity Waterflooding?
Authors: Kasmaei A. Kafili , Rao D. N. 
Published: June 2014

Abstract
Low salinity waterflooding is gaining some attention in the recent literature as a means of improving oil recoveries. However, a clear understanding of the key mechanism(s) of low-salinity waterflooding does not seem to have emerged although wettability alteration is repeatedly cited as the cause for the observed effects, albeit without much experimental evidence. Moreover, much of the reported low-salinity work appears to be related to sandstone reservoirs.
In this study, we have attempted to investigate the role wettability alteration plays in low-salinity waterflooding by conducting dual-drop-dual-crystal contact angle measurements to characterize wettability changes and coreflood experiments for oil recovery and oil/water relative permeability measurements using a dolomite reservoir rock-fluids system. Additional experiments have been conducted to examine the roles of brine chemistry and the temperature in altering wettability in low-salinity waterfloods.
The contact angle results clearly indicate the wettability alteration from an oil-wet state (with a water-advancing contact angle of 158°) to an intermediate state (with an advancing contact angle of 113°) caused by diluting the reservoir brine to one-fiftieth of its original strength. A similar result was obtained when the sulfate concentration in the reservoir brine was doubled and when the temperature was increased to 250°F from the reservoir temperature of 80°F. These wettability alterations as measured by contact angles were confirmed by coreflood experiments that yielded significantly higher recoveries (from about 46% to about 76%) due to low-salinity flooding, alteration of brine composition and temperature.
This experimental study confirms the major influence of wettability in low-salinity waterflooding of a dolomite reservoir.
Analyzing the Reservoir Performance of an Expanding Solvent - Steam Assisted Gravity Drainage (ES-SAGD) Process Using a Semi-Analytical Approach
Authors: Kannan K. , Srinivasan S. 
Published: June 2014

Abstract
Steam Assisted Gravity Drainage (SAGD), through many successful field projects, has proven to be an effective process for improved recovery of heavy oil and bitumen from subsurface reservoirs. However, the continued search for a more energy efficient method has led to the development of an improved process called Expanding Solvent (ES)-SAGD that has the potential to accelerate recovery with less steam requirement per barrel of oil produced. Understanding the physics associated with this process is key for making robust predictions regarding the process performance. In this paper, a semi-analytical model is discussed, which can be used to determine the performance of the ES-SAGD process. The results of the semi-analytical model are compared to 2D numerical simulation results in order to validate the model.
The semi-analytical model, an extension to the model by Gupta et al. (2012) is developed by combining Butler's (Butler et al., 1981, 1985) oil drainage analytical expression for SAGD and VAPEX (Gupta el., 2010) solvent dilution effects. This approach, with some modifications, is validated by the use of a 2D simulation. Numerical simulation of a short length-scale process like solvent dilution in oil sometimes may yield less accurate result prediction due to inherent numerical dispersion issues. Dynamic gridding based on both temperature and concentration change criterion is demonstrated to be one of the viable options to obviate this issue.
Trends for bitumen production rate and some key operation parameters obtained using the semi-analytical model are in good agreement with the numerical simulation results, rendering this model suitable for performing solvents-screening studies. However, there are some differences in magnitude of the results between the simulation and semi-analytical method that can be attributed to grid orientation effects. Modifications to the semi-anlayitcal approach and reservoir model used in 2D simulations have been made to minimize the observed differences.
It can be concluded that the approach discussed in this paper could give a preliminary estimate of the key parameters that affect the recovery using the ES-SAGD process. The paper also presents some useful guidelines for simulating the process performance using current commercial simulators.
Synergistic Stabilization of Foams by a Mixture of Nanoparticles and Surfactants
Authors: Singh Robin , Mohanty Kishore K. 
Published: June 2014

Abstract
The goal of this work is to evaluate stabilization of foams by a combination of nanoparticles and surfactants. Hydrophilic silica nanoparticles (NP) and anionic surfactants were used in this study. Static foams were generated using surfactants and surfactant-NP mixtures with and without the presence of a crude oil. The decay of the foam height with time was studied and half-lives were determined. The foam drainage behavior and thickness of the foam lamella were studied by fluorescence microscopy. Aqueous foams were created in-situ by co-injecting the surfactant or surfactant-NP mixtures with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). Oil displacement experiments were conducted in Berea cores using surfactant and surfactant-nanoparticle mixture as foaming agents. Static foam tests indicate stabilization effect of nanoparticles on surfactant-nanoparticle foam stability in the absence of crude oil. Lighter crude oils were more destabilizing to foams than heavier oils. Adding nanoparticles even in low concentrations (0.3 wt %) can significantly improve the foam stability and mobility reduction factor in the absence of oil. As the concentration of nanoparticles increased, mobility reduction factor (MRF) of surfactant-nanoparticle foam in a Berea core increased significantly. Fluorescence microscopy elucidated that nanoparticles are trapped in the plateau border as well as lamellas which retard liquid drainage and bubble coalescence. The core floods with a crude oil revealed that the incremental oil recovery by surfactant-NP blend over water flood was about 10% OOIP with an immiscible foam.