bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved/Enhanced Oil Recovery from Carbonate Reservoirs by Tuning Injection Water Salinity and Ionic Content
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed 
Published: April 2012

Abstract
Improved/enhanced oil recovery by tuning the ionic composition of the injection water is currently deemed as new emerging recovery method. In the recent years, extensive research on oil/brine/rock systems has shown that injecting low salinity brines has a significant impact on oil recovery from sandstone reservoirs. Although, the potential for carbonates has not been carefully investigated, some reported studies have excluded carbonates from this effect.
In view of research results for the last three years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593, SPE 143550, SPE 141082) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing ionic composition of field injection brine. Also, research confirmed that the driving mechanism is wettability alteration. In this paper, we present the results of new reservoir condition laboratory coreflooding studies, conducted using composite rock samples from different carbonate reservoir, to investigate the impact of ionic content on oil recovery at both secondary and tertiary recovery modes. Also, we report a broad range of laboratory studies addressing role of water ions. In addition, we briefly disclose the results of first-ever field application conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential.
The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the ionic content of field injection water. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, the new results confirmed that wettability alteration is the main cause for the substantial increase in oil recovery. Compared to previous reported work, the variation in oil recovery from two different carbonate reservoirs is attributed to the variations in reservoir temperature and also the chemistry of initial formation water. For field application, two field trials confirmed that injection of SmartWater achieved ∼7 saturation units reductions in residual oil beyond conventional seawater flooding. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood is emerging recovery method targeting carbonate reservoirs.
Coupling of Stress Dependent Relative Permeability and Reservoir Simulation
Authors: Ojagbohunmi Samuel , Chalaturnyk Rick , Leung Juliana 
Published: April 2012

Abstract
Geomechanics is increasingly being considered for inclusion in reservoir simulation, since conventional simulators do not honor deformation resulting from the interaction between stress and fluid flow response in a porous medium.
When a reservoir responds to changes in effective stress, the bulk volume adjusts, changing the pore geometry and dependent parameters like porosity, absolute permeability and effective permeability, and phase saturations. Most of the recently developed sequentially coupled approaches for coupling flow and geomechanics have focused on updating porosity and absolute permeability while changes in relative permeability (due to geomechanics) is ignored. For multiphase flow systems, relative permeability functions are one of the most influential parameters controlling fluid movement and distribution. To examine how geomechanically-influenced relative permeability may impact flow, a sequentially coupled reservoir geomechanical simulation study was conducted. The simulation workflow incorporated automatic updates of the relative permeability table for each grid block in the model at every time-step. Data for populating the geomechanical relative permeability tables was extracted from recent experimental test results reported in the literature.
Results from the simulation studies showed a significant difference in recovery factors when the impact of geomechanics on relative permeability functions was integrated into coupled simulation compared to when only changes in porosity and absolute permeability were used.
Coupled models which incorporate not only the change in permeability and porosity but also the changes in relative permeability can lead to more realistic production forecast especially for reservoirs under improved or enhanced oil recovery scheme as found in heavy oil and oil sands projects.
Mobility and Conformance Control for CO2 EOR via Thickeners, Foams, and Gels - A Literature Review of 40 Years of Research and Pilot Tests
Authors: Enick R. M. , Olsen D. , Ammer J. , Schuller W. 
Published: April 2012

Abstract
Carbon dioxide (CO2) has been used commercially to recover oil from geologic formations by enhanced oil recovery (EOR) technologies for over 40 years. The U.S. Department of Energy Office of Fossil Energy and its predecessor organizations have supported a large number of laboratory and field projects over the past decades in an effort to improve the oil recovery process including investments to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. Currently, CO2 EOR provides about 280,000 barrels of oil per day, just over 5 percent of the total U.S. crude oil production. Recently CO2 flooding has become so technically and economically attractive that CO2 supply, rather than CO2 price, has been the constraining developmental factor. Carbon dioxide EOR is likely to expand in the United States in upcoming years due to "high" crude oil prices, natural CO2 source availability, and possible large anthropogenic CO2 sources through carbon capture and storage (CCS) technology advances. Despite its well-established ability to recover oil, the CO2 EOR process could be improved if the high mobility of CO2 relative to reservoir oil and water can be effectively and affordably reduced. The CO2 EOR industry continues to use water-alternating-with-gas (WAG) as the technology of choice to control CO2 mobility and/or mechanical techniques (e.g., cement, packers, well control, infield drilling, and horizontal wells) to help control the CO2 flood conformance. If the "next generation" CO2 EOR target of 67 billion barrels is to be realized, new solutions are needed that can recover significantly more oil than the 10–20% of the original oil in place associated with current flooding practices. A recent literature review [Enick and Olsen, 2011] concentrates on the history and development of CO2 mobility control and profile modification technologies in the hope that stimulating renewed interest in these chemical techniques will help to catalyze new efforts to overcome the geologic and process limitations such as poor sweep efficiency, unfavorable injectivity profiles, gravity override, high ratios of CO2 to oil produced, early breakthrough, and viscous fingering. This paper is a concise overview of the recent, comprehensive literature review available on the NETL website entitled "Mobility and Conformance Control for Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) via Thickeners, Foams, and Gels – A Detailed Literature Review of 40 Years of Research" [Enick and Olsen, 2011] that focuses on attempts to enhance carbon dioxide mobility control (in-depth, long-term processes that cause CO2 to exhibit mobility comparable to oil) and profile modification/conformance control (near-wellbore, short-term process primarily intended to greatly reduce the permeability of a thief zone) using CO2 thickeners and CO2 foams. In particular, this paper focuses on the history of CO2 thickeners.
Numerical Simulation of Electromagnetic Driven Heavy Oil Recovery
Authors: Bogdanov Igor , Torres Jose Antonio , Corre Bernard 
Published: April 2012

Abstract
This work presents a feasibility study of a heavy oil recovery process driven by electromagnetic heating (EMH). Previously EMH has been subject of many research works on heavy oil recovery, including laboratory, theoretical and numerical simulation studies. These works have demonstrated that EMH constitutes a promising recovery process; however the simulations of this challenging coupled multi-physics phenomenon were not straightforward and required special efforts in model development.
The major part of previous theoretical and numerical models has been based on simplifications of the Maxwell equations for the EMH source description. The advantage of such a model is its simplicity which helps to gain a conceptual knowledge via order of magnitude estimations at reasonable computational expenses. A typical example is the use of conventional constitutive relation for the EMH source, i.e. the so-called Beer-Lambert-Bouguer law which, strictly speaking, can be applied to a limited number of practically valuable cases. Other models are required, for instance, to estimate the influence of water evaporation and resulting multiphase flow on EMH driven oil recovery.
Taking advantage of a coupled numerical simulation tool recently developed in our group, a few instructive EMH application cases capturing the effects of EM wave propagation in a non-homogeneous medium, on one side, and thermal multiphase flow in a heavy oil reservoir, on the other, are presented and analyzed in this paper.
Major attention is paid to the production efficiency. Conventional criteria adopted for such an IOR method may not be always applicable, so a comparison to known methods like SAGD or recovery by conductive heating is provided for analysis purposes. Although a number of process scenarios and options are possible, in our current study we chose for the base case a horizontal SAGD-like well pair, the upper well being equipped with an EM wave emitting facility (the EM well). Different process stages (preheating, steam chamber offset and development, and production) are considered in detail and the critical analysis of heating zone and oil flow configurations is done to find out conditions of improved recovery. In particular, the results indicate that while the preheating period can be successfully modeled using the BLB law, starting from the steam chamber offset a more realistic electromagnetic model is to be applied to adequately describe EMH heating source and production dynamics.
The EMH assisted recovery process is a promising IOR method especially for unconventional oil reservoirs. The results obtained in this work via coupled EMH/reservoir flow simulations provide an improved understanding on this challenging multi-physics problem.
Low Salinity Water Flooding Experiments and Interpretation by Simulations
Authors: Fjelde Ingebret , Asen Siv Marie , Omekeh Aruoture 
Published: April 2012

Abstract
Even though the proposed screening criteria for low salinity water flooding (LSWF) are fulfilled, improve recovery is not always obtained. The LSWF mechanisms are therefore still discussed. The objective for the study was to describe the brine-rock interactions at high and low salinity. Reservoir core plugs were flooded either by formation water, sea water and low salinity waters in succession or by low salinity water directly from initial water saturations. Effluent samples were analyzed for ionic concentrations and pH. Relative permeability (kr) and capillary pressure (Pc) curves were obtained at the core scale by history matching the experimental production and differential pressure across cores using a simulation tool. A developed two-phase model was used to predict the release of divalent cations from the rock during LSWF, and to relate this to the oil recovery.
The high salinity water flood with formation water was found to give close to piston-like displacement, while the oil was produced over much longer periods in LSWF. The estimated kr- and Pc-curves indicated that the rock was water-wet in the high salinity floods and mixed-wet in the low salinity floods. The experimental results were in accordance with the modeling of the brine-rock interactions. When the formation water was replaced with the low salinity water, increase in the concentrations of divalent cations onto clay surfaces was predicted for the selected brine compositions. Higher concentrations of polar oil components can then be bonded to the clay surfaces by the divalent cations and make them less water-wet. It is concluded that the low salinity water altered the wetting state of the rock. The direction of alteration can be explained by ion exchange taking place on the clay surface. The low salinity water potential for improving recovery should be considered on a case by case basis based on the interactions between the formation brine, injected brines, oil components, and rock type.
Modeling of Ion-Exchange and Solubility in Low Salinity Water flooding
Authors: Omekeh Aruoture , Friis Helmer André , Fjelde Ingrebet , Evje Steinar 
Published: April 2012

Abstract
The potential of low salinity water flooding (LSWF) to improve oil recovery in sandstone cores has been well documented. The objective of this paper is further development and examination of a one-dimensional mathematical model for the study of water flooding laboratory experiments. The model describes how dissolution/precipitation of various carbonate minerals and multiple ion-exchange (MIE) will have an impact on the water-oil flow function. The model is formulated such that the total release of divalent cations from the rock surface will give rise to a change of the relative permeability such that more oil is mobilized. The combined effect of MIE and dissolution/precipitation was modelled to determine how this will affect pH and the total release of divalent cations
The effects of solubility of carbonate minerals on the ion exchange process during the LSWF have been studied. Dynamic experiments were carried out using brines with different compositions and reservoir rocks. The ion concentrations and pH in effluent samples were determined.
In experiments, pH was found to increase during the interaction between low-salinity brine and reservoir rocks. The ion composition of the low salinity brine was also found to change due to interaction with the reservoir rocks. The model developed successfully matched the experimental results. The simulation results show that dissolution of carbonate minerals can occur and this will then alter the composition of the injected low-salinity brine, the concentration of divalent ions on the rock surface and hence the potential of low salinity to improve recovery.
It is important during the evaluations of the potential for LSWF to take into account that dissolution of minerals can change the composition of the injected low salinity brine. The potential should be evaluated using the composition that the brine will have in the main part of the reservoir.
Chemical EOR Pilot in Mangala Field: Results of Initial Polymer Flood Phase
Authors: Pandey Amitabh , Kumar M. Suresh , Jha Manish Kumar , Tandon Rohit , Punnapully Brennan S , Kalugin Mavriky , Khare Ashish , Beliveau Dennis 
Published: April 2012

Abstract
The Mangala field in the Rajasthan state of western India was the first major oil discovery in the Barmer Basin. It contains over 1 billion bbls of paraffinic oil with average viscosity of ~15cp and wax appearance temperature only ~5°C less than reservoir temperature. The initial development plan is a hot waterflood to prevent in situ wax deposition; however, chemical EOR methods are expected to play an important role in the ultimate field development strategy.
EOR assessment was part of the initial field development planning process. Screening studies were conducted soon after discovery followed by comprehensive laboratory evaluations of chemical flood potential which had been identified as the most suitable process. The laboratory evaluation along with parametric simulation studies indicated significant chemical EOR potential. A closely spaced normal 5-spot pilot was designed to test chemical EOR processes in the early part of the field development. Logging observation wells are strategically placed in the pilot to periodically monitor changes in oil saturation.
The initial waterflood phase in the pilot has been completed and injection of the polymer slug is in progress. Comprehensive monitoring and quality control procedures are being followed to ensure smooth operations. Extensive PLTs, time-lapse saturation and resistivity logs, pressure surveys, tracer surveys, detailed produced fluid analyses and tests for monitoring the quality of injected fluids are all performed routinely. Dynamic reservoir modeling has been a critical part of the analysis to understand polymer flood behavior. The initial polymer flood phase in the pilot will be followed by ASP (alkaline-surfactant-polymer) injection for further evaluation of chemical EOR potential.
This paper discusses the operational aspects of polymer flood facilities, quality control and monitoring program followed, challenges faced, polymer injection results and plans for future ASP injection.
CO2 Injection in Porous Media: Observations in Glass Micromodels Under Reservoir Conditions
Authors: Robin M. , Behot J. , Sygouni V. 
Published: April 2012

Abstract
CO2 injection process is of high interest in applications such as CO2 storage in reservoir rocks, enhanced oil recovery or soil remediation. The optimization of such a process requires a detailed reservoir petrophysical description but also representative three-phase transport properties in porous media. Imbibition and drainage processes are dominated by interfacial phenomena. The displacement mechanisms are affected by wettability and interfacial tensions.
A series of experiments were conducted in glass micromodels of varying wettability, aiming at describing three phase displacements involving brine, oil and CO2. They have been conducted under various conditions of pressure and temperature.
Experiments under varying thermodymic conditions (gaseous, liquid and supercritical CO2) were conducted on porous media of different wettabilities. Fluids distribution within the porous medium under reservoir conditions was visualized and conclusions concerning important parameters such as the spreading coefficient which plays a major role in oil recovery were drawn. These observations were confirmed by core scale experiments such as capillary pressure curves and displacements at the core scale.
Additionally, we observed the in situ formation of CO2 foams generated from surfactants dissolved in the aqueous phase. These foams (or emulsions) were also formed from gaseous, liquid or supercritical CO2. CO2 and surfactant solutions were co injected in the porous media. Foam formation and evolution from the inlet to the outlet of the porous medium was followed.
Pore-Scale Evaluation of Polymers Displacing Viscous Oil – Computational Fluid Dynamics Simulation of Micromodel Experiments
Authors: Clemens Torsten , Tsikouris Kostas , Buchgraber Markus , Castanier Louis , Kovscek Anthony 
Published: April 2012

Abstract
Recovery of viscous oil can be significantly improved by injecting polymer solutions. The processes leading to increased oil production occur on a large scale – improving vertical and areal sweep efficiency – but they begin on a micro scale.
Micromodels with realistic pore geometries have been created. These micromodels were saturated with viscous oil and the displacement of the oil by water and polymer solutions investigated experimentally. Polymer injection reduced fingering compared with water injection and increased sweep efficiency accordingly.
The micromodel pore network geometry was digitised using Scanning Electron Microscopy (SEM). The digitised model was used to perform Computational Fluid Dynamics Simulations (CFD) of the displacement processes.
The displacement efficiencies and displacement patterns of the CFD simulations using water, polymer solutions, and polymer solutions after water breakthrough at the outlet end to displace oil were very similar to the results of the micromodel experiments.
Then, the CFD simulations were used to investigate the displacement at the pore scale. Water injection leads to creation of fingers along slightly more permeable flowpaths. The number and length of the fingers decreases if polymer solution is injected. Even for polymer injection after water breakthrough, the fingering is reduced, polymer solutions are diverted into less favourable flow paths and sweep efficiency is increased.
CFD simulations can also be used to look into nonNewtonian fluid behaviour at the pore scale. The polymers injected in the micromodel experiments exhibited shear-thinning behaviour. On a pore scale, CFD simulations showed that the shear stress and viscosity of the polymer solutions accordingly are significantly lower in the pore throats than in the pores. Hence, the displacement efficiency of the polymer solutions is impacted by the shear-thinning behaviour.
The CFD simulations are in remarkable agreement with the micromodel experiments and can be used to quantify the displacement processes at pore scale.
Gravity-Enhanced Transfer between Fracture and Matrix in Solvent-Based Enhanced Oil Recovery
Authors: Kahrobaei S. , Farajzadeh R. , Suicmez V. S. , Bruining J. 
Published: April 2012

Abstract
Solvent injection has been considered as an efficient method for enhancing oil recovery from fractured reservoirs. If the mass transfer would be solely based on diffusion, oil recovery would be unacceptably slow. The success of this method therefore depends on the degree of enhancement of the mass exchange rate between the solvent residing in the fracture and the oil residing in the matrix.
A series of soak experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. In a soak experiment, a porous medium containing oil is immersed in an open space containing the solvent to simulate the matrix and the fracture respectively. We use a CT scanner to visualize the process. The experimental data are compared with a simulation model that takes diffusive and gravitational forces into account.
We find that the initial stage of all experiments can be described by a diffusion-based model with an enhanced "effective diffusion coefficient". In the second stage enhancement of the transfer rate occurs due to the natural convection of solvent in the fracture. The experiments are quantitatively modeled by numerical simulations. We find that transfer rates depend on the properties of the rock permeability, the viscosity and the density of solvent and oil. The gravity enhanced transfer is quantified by comparison of experimental and simulated results.