Oil In Porous Media Research Articles

Simulation of kinetic behavior of natural surfactants adsorption using a new robust approach

AbstractSurfactant‐based enhanced oil recovery techniques are known as promising methods for mobilizing the trapped oil in porous media. Surfactants can improve oil recovery by modifying the wettability of rock minerals and also by reducing the interfacial tension between injected water and the trapped oil. Natural surfactants have been introduced as good candidates for enhanced oil recovery applications. In addition, they are less expensive and also have less detrimental environmental effects in comparison with the industrial surfactants. Various empirical models have been proposed for simulating the kinetic behavior of surfactants adsorption, but these models suffer from overestimation and underestimation and they cannot be generalized for even a type of surfactant. Therefore, it is crucial to develop a new model that can overcome these issues. In this study, a new simple, rapid, and accurate model based on least square support vector machines (LSSVMs) was developed for predicting the kinetic adsorption density of natural surfactants on both sandstone and carbonate minerals. Coupled simulated annealing algorithm (CSA) is used for tuning the parameters of the model. Predicted values by this model were in an excellent agreement with experimental values with a coefficient of determination of 0.990. The results demonstrated that the proposed LSSVM‐CSA model has the best performance in comparison with the other well‐established kinetic models. Furthermore, the model reliability was investigated over input parameters changes and showed the acceptable efficiency of the proposed model.

NUMERICAL SIMULATION OF FILTRATION PROCESSES OF STRONGLY POLLUTED OIL IN A POROUS MEDIUM

Ponte Academic JournalNov 2018, Volume 74, Issue 11 NUMERICAL SIMULATION OF FILTRATION PROCESSES OF STRONGLY POLLUTED OIL IN A POROUS MEDIUMAuthor(s): Ravshanov Normakhmad ,Elmira NazirovaJ. Ponte - Nov 2018 - Volume 74 - Issue 11 doi: 10.21506/j.ponte.2018.11.10 Abstract:The work is devoted to solving the actual problem of forecasting the development of the oil and gas industry. The article discusses the non-stationary filtration process of highly contaminated oil in a heterogeneous porous medium in a two-dimensional formulation. A detailed analysis of scientific papers related to the problem of mathematical modeling of the filtering process of heavily contaminated oils in porous media is given. The arbitrariness of the field configuration and the variation of the reservoir parameters over the reservoir area, the unevenness of the location of oil wells in the oil-bearing area and their variability of flow rates, which are not limiting factors for the use of numerical modeling in the calculations of oil field development, are given. A mathematical model has been developed that takes into account such factors as the rate of sedimentation of fine particles, the change in the coefficients of porosity and filtering over time. The mathematical model is reduced to the joint solution of a system of differential equations of a parabolic type, describing filtration processes in seams separated by a low-permeable jumper under appropriate initial and boundary conditions. Computational experiments are given at different parameters of the reservoir and the costs of two production wells. Given the results of the developed software, which presents the results of the calculation of the main indicators of development of fields in tabular and graphical form. All results of computational experiments are presented in visual form. Download full text:Check if you have access through your login credentials or your institution Username Password

Non-Newtonian Flow Characteristics of Heavy Oil in the Bohai Bay Oilfield: Experimental and Simulation Studies

In this paper, physical experiments and numerical simulations were applied to systematically investigate the non-Newtonian flow characteristics of heavy oil in porous media. Rheological experiments were carried out to determine the rheology of heavy oil. Threshold pressure gradient (TPG) measurement experiments performed by a new micro-flow method and flow experiments were conducted to study the effect of viscosity, permeability and mobility on the flow characteristics of heavy oil. An in-house developed novel simulator considering the non-Newtonian flow was designed based on the experimental investigations. The results from the physical experiments indicated that heavy oil was a Bingham fluid with non-Newtonian flow characteristics, and its viscosity-temperature relationship conformed to the Arrhenius equation. Its viscosity decreased with an increase in temperature and a decrease in asphaltene content. The TPG measurement experiments was impacted by the flow rate, and its critical flow rate was 0.003 mL/min. The TPG decreased as the viscosity decreased or the permeability increased and had a power-law relationship with mobility. In addition, the critical viscosity had a range of 42–54 mPa∙s, above which the TPG existed for a given permeability. The validation of the designed simulator was positive and acceptable when compared to the simulation results run in ECLIPSE V2013.1 and Computer Modelling Group (CMG) V2012 software as well as when compared to the results obtained during physical experiments. The difference between 0.0005 and 0.0750 MPa/m in the TPG showed a decrease of 11.55% in the oil recovery based on the simulation results, which demonstrated the largely adverse impact the TPG had on heavy oil production.

Microemulsion-enhanced displacement of oil in porous media containing carbonate cements

Subsurface porous formations containing nonaqueous phase liquids (NAPLs) such as crude oils are often targets for surfactant flooding during enhanced oil recovery (EOR) or aquifer remediation processes designed to mobilize and solubilize oil. Recent studies suggested that putting surfactants into micro-emulsified state prior to injection might improve their performance. Most of these studies proved that microemulsion (ME) efficiency depends on test conditions and the proper selection of their chemical formulations and brine chemistry. However, the impact of rock characteristics on the complex fluid-rock interactions is still unclear, especially in heterogeneous rocks. The goal of this fundamental study was to examine the effect of MEs on oil displacement in three different aged rocks (Berea, Edwards, and Tensleep) and identify the test conditions in which MEs outperform surfactants. The effectiveness of surfactants and MEs was evaluated at two concentrations from different sets of spontaneous imbibition tests and petrographic analyses. Several mechanisms such as reduction of interfacial tension (IFT), oil emulsification, and wettability alteration were responsible for the improved recovery. Wettability alteration of aged cores by surfactants and MEs led to an early oil removal by spontaneous imbibition while emulsification increased the ultimate amount produced. Both additives lowered the IFT from 12 to less than 1 mN/m. However, high ME concentration was able to decrease the size of oil droplets by one order of magnitude, significantly enhancing oil mobilization in all three rocks. The solubilization capability of MEs was superior in Tensleep due to their unique ability to penetrate dolomite cements and alter their wettability.

Pore-scale investigation of residual oil distributions and formation mechanisms at the extra-high water-cut stage

Water flooding has been widely applied in the oilfield development as a secondary recovery method due to its effectiveness and economic feasibility. After several decades of production, numerous oil fields are normally entering into the extra-high water-cut stage (water cut higher than 90%). The extra-high water-cut stage takes an extremely important role in the whole development process since a large amount of residual oil remains trapped in reservoirs (approximately 50% to 60% of initial oil in place) at this stage. The extensively continuous distribution of subsurface oil at the low water-cut stage has changed greatly after the water cut of mature oilfields becomes over 90%. The residual oil distributes mainly in a scattered state at the extra-high water-cut stage, while water flows in a continuous state. Oilfields with high water cut are normally suffering from poor flooding efficiency, to improve water flooding efficiency, it is necessary to understand distributions and formation mechanisms of residual oil at the extra-high water-cut stage. In this study, a pore-scale simulation model is developed to exploit the potential of residual oil in a porous media. A direct numerical simulation method is employed to simulate fluid flow in a porous media, the position of interface between water and oil is determined by the phase field method. The capacity and accuracy of the model is validated by a classical benchmark: a layered two-phase flow with a variable viscosity ratio. The formation processes of residual oil and mechanisms behind this are investigated in terms of mechanics. The results show that the residual oil in porous media at the extra-high water-cut stage can be classified as five types, namely, isolated oil droplet, residual oil in pore throats, cluster residual oil, oil film and residual oil in dead end. Rock configuration, wettability and capillary pressure play important roles in the formation of residual oil. The formation of isolated oil droplet is dominated by rock configuration, capillary pressure and wettability. Capillary pressure and wettability are key factors for the formation of residual oil in pore throats. Rock configuration and capillary pressure are responsible for the formation of cluster residual oil. Wettability is the dominant factor for the formation of oil film. The relationship between cumulative water production and cumulative oil production is consistent at the pore scale and Darcy scale. Relative permeability curve is obtained based on the pore-scale simulation and an upward turning is observed after the water cut reaches 98%. Increasing injection velocity and injection of surfactant can both displace cluster residual oil, residual oil in pore throats and isolated oil droplets, which leads to the increase in oil recovery at the extra-high water-cut stage. The decline in cluster residual oil is the main contributor to rise in oil recovery. Times of increasing injection velocity have an important pact on the field development. This study is only conducted in a two dimensional porous media, and more factors (e.g., gravity) should be incorporated into our model to investigate the formation process of residual oil in the three dimensional porous media.

Intermittent CO2 and viscosity-reducing gas (VRG) injection for enhanced heavy oil recovery

The results of three coreflood experiments are reported which were performed to investigate intermittent CO2 and viscosity-reducing gas (VRG) injection for enhanced heavy oil recovery (EHOR). This injection strategy is particularly suitable for heavy and viscous oil reservoirs as it enhances the contact between the resident oil and injected fluid. The recovery efficiency of continuous injection is low due to the high viscosity ratio between the oil and injection fluid. The intermittent injection of liquid CO2 for 4cycles resulted in the recovery of 12% of the initial oil in place (IOIP) while in the second experiment, 9cycles of intermittent supercritical CO2 injection recovered 38% IOIP. In the third experiment, 5cycles of intermittent VRG injection led to the recovery of 22% IOIP. The results demonstrate that a higher quality oil than the original oil in the core is recovered during the periods of CO2 and VRG injection. However, it is shown that different mechanisms were contributing to oil recovery during CO2 and VRG injection. The results of the simulation study imply that the mechanism of extraction of hydrocarbons by CO2 would be an important reason for the recovery of higher quality oil during the periods of CO2 injection whereas its impact is less pronounced when the injection gas is a hydrocarbon gas. However, the extraction of hydrocarbons to the CO2-rich phase could not be fully responsible for the higher quality oil recovery and it is discussed that how this mechanism could affect the flow of CO2 and oil in porous media.

Cation Exchange in the Presence of Oil in Porous Media.

Cation exchange is an interfacial process during which cations on a clay surface are replaced by other cations. This study investigates the effect of oil type and composition on cation exchange on rock surfaces, relevant for a variety of oil-recovery processes. We perform experiments in which brine with a different composition than that of the in situ brine is injected into cores with and without remaining oil saturation. The cation-exchange capacity (CEC) of the rocks was calculated using PHREEQC software (coupled to a multipurpose transport simulator) with the ionic composition of the effluent histories as input parameters. We observe that in the presence of crude oil, ion exchange is a kinetically controlled process and its rate depends on residence time of the oil in the pore, the temperature, and kinetic rate of adsorption of the polar groups on the rock surface. The cation-exchange process occurs in two stages during two phase flow in porous media. Initially, the charged sites of the internal surface of the clays establish a new equilibrium by exchanging cations with the aqueous phase. At later stages, the components of the aqueous and oleic phases compete for the charged sites on the external surface or edges of the clays. When there is sufficient time for crude oil to interact with the rock (i.e., when the core is aged with crude oil), a fraction of the charged sites are neutralized by the charged components stemming from crude oil. Moreover, the positively charged calcite and dolomite surfaces (at the prevailing pH environment of our experiments) are covered with the negatively charged components of the crude oil and therefore less mineral dissolution takes place when oil is present in porous media.

Relative Flow of Bacteria and Oil in Porous Media

Relative Flow of Bacteria and Oil in Porous Media

Experiment on the Influence Factors of Steam Distillation Rate of Crude Oil in Porous Media

To explore the influence of complexity of reservoir properties in porous media and the diversity of operating conditions on the steam distillation rate of crude oil in the process of heavy oil exploitation with steam injection, steam distillation simulation devices are used to study steam distillation rate of crude oil in porous media. Then steam distillation ratio is obtained under the condition of different core permeability, oil saturation, steam temperatures, system pressure, steam injection rates and steam distillation rates with different viscosities of crude oil. The results show that the steam distillation rate of crude oil in porous media depends mainly on the nature of the crude oil itself, for temperature and pressure are the key factors compared with the pore structure, the initial oil saturation and steam injection rate. The experimental results help estimate the amount of crude oil and the required steam in the reservoir in the steam drive process, aiming to facilitate the optimization design and operation of steam drive.

Experimental Study on Water Sensitivity Difference Based on Oiliness of Porous Medium Rock

This study presents the differences of water sensitivity experiment of porous medium rock between conventional dry core samples and oil-bearing core. The comparison was made to analyze the impact of single-phase fluid and multiphase fluid on the actual sensitivity of rock. The nuclear magnetic resonance (NMR) test was carried out to reveal the distribution of oil in porous medium and the microscopic influence mechanism of oil phase. The study shows that the initial oil in place could isolate the clay from water, and then the expansion and the migration of the clay were prevented to reduce the decrease of degree of damage.

Investigation of foam flow in a 3D printed porous medium in the presence of oil

Foams demonstrate great potential for displacing fluids in porous media which is applicable to a variety of subsurface operations such as the enhanced oil recovery and soil remediation. The application of foam in these processes is due to its unique ability to reduce gas mobility by increasing its effective viscosity and to divert gas to un-swept low permeability zones in porous media. The presence of oil in porous media is detrimental to the stability of foams which can influence its success as a displacing fluid. In the present work, we have conducted a systematic series of experiments using a well-characterised porous medium manufactured by 3D printing technique to evaluate the influence of oil on the dynamics of foam displacement under different boundary conditions. The effects of the type of oil, foam quality and foam flow rate were investigated. Our results reveal that generation of stable foam is delayed in the presence of light oil in the porous medium compared to heavy oil. Additionally, it was observed that the dynamics of oil entrapment was dictated by the stability of foam in the presence of oil. Furthermore, foams with high gas fraction appeared to be less stable in the presence of oil lowering its recovery efficiency. Pore-scale inspection of foam-oil dynamics during displacement revealed formation of a less stable front as the foam quality increased, leading to less oil recovery. This study extends the physical understanding of oil displacement by foam in porous media and provides new physical insights regarding the parameters influencing this process.

Mn-Catalyzed Oxidation of Heavy Oil in Porous Media: Kinetics and Some Aspects of the Mechanism

Mn-catalyzed oxidation of the Ashalcha heavy oil in porous media was examined. We used manganese(III) tris(acetylacetonate) as a convinient oil-soluble precatalyst that decomposes to catalytically active species during the temperature ramping. Reaction kinetics in the heavy oil oxidation with air indicated that the presence of the manganese ions changes the mechanism of the oxidation process, especially in the high-temperature region. To study precatalyst transformations in detail, we suggested the approach of combining X-ray powder diffraction (XRPD), thermal analysis, non-isothermal kinetic methods, and electron paramagnetic resonance (EPR). A comprehensive study of the decomposition of pure manganese(III) tris(acetylacetonate) and the subsequent comparison of its behavior to that in porous media in the presence of the oil allows us to shed light on some aspects of the mechanism of catalytic oxidation.

A novel method to model and characterize in-situ bio-surfactant production in microbial enhanced oil recovery

Capillary force is an important factor that limits the efficiency of water flooding by trapping the oil in porous media. High capillarity is caused by high interfacial tension (IFT) between oil and water that leads to a high residual oil saturation. Surfactants are widely used to reduce IFT and significantly mobilize the entrapped oil. However, the surfactants that are injected into a reservoir to lower the IFT several orders of magnitude may not be cost effective. Microbial enhanced oil recovery (MEOR) process may potentially address a cost effective alternative to surfactant flooding. In the MEOR process, nutrients and natural bacteria are injected into a reservoir and both indigenous and injected microorganisms are able to react and then generate biosurfactants based on in-situ reactions.Modeling of microbial enhanced oil recovery requires coupling kinetics transport with local equilibrium transport in the presence of the surfactant phase behavior model (i.e. Hand’s rule). In general, reservoir simulators do not model relative chemical reactions that consider the effect of essential environmental parameters such as temperature, salinity, and pH.The main objective of this work is to present first order Monod kinetic equations as a function of temperature, salinity, and pH, which control the biodegradation reactions and microbial growth rate. Furthermore, the impact of biosurfactant adsorption, maximum growth rate, and nutrient concentration are systematically investigated. Also, the effects of environmental factors are implemented in a four-phase chemical flooding reservoir simulator (UTCHEM). Subsequently, the simulator is used to history match a coreflood experimental data to model the contribution of cited parameters on oil recovery.Results show that in-situ biosurfactant generation rates can be thoroughly modeled based on environmental factors IFT can be reduced in a similar manner as surfactants. Simulation results show 10–15% incremental oil recovery using in-situ biosurfactant compared to waterflooding. Moreover, based on the simulation results, nutrient concentration, salinity and temperature are found to be the most significant parameters influencing oil recovery, whereas pH has insignificant effect.The understanding of in-situ biosurfactant generation in a MEOR process, implementing a new environmental model into the simulator, and investigating of various parameters influencing the efficiency of the MEOR process are the key findings of this work.

Effect of Temperature on the Gas/Oil Relative Permeability of Orinoco Belt Foamy Oil

Summary Foamy-oil flow has been successfully demonstrated in laboratory experiments and site applications. On the basis of solution-gas-drive experiments with Orinoco belt heavy oil, the effects of temperature on foamy-oil recovery and gas/oil relative permeability were investigated. Oil-recovery efficiency increases and then decreases with temperature and attains a maximum value of 20.23% at 100°C. The Johnson-Bossler-Naumann (JBN) method has been proposed to interpret relative permeability characteristics from solution-gas-drive experiments with Orinoco belt heavy oil, neglecting the effect of capillary pressure. The gas relative permeability is lower than the oil relative permeability by two to four orders of magnitude. No intersection was identified on the oil and gas relative permeability curves. Because of an increase in temperature, the oil relative permeability changes slightly, and the gas relative permeability increases. Thermal recovery at an intermediate temperature is suitable for foamy oil, whereas a significantly higher temperature can reduce foamy behavior, which appears to counteract the positive effect of viscosity reduction. The main reason for the flow characteristics of foamy oil in porous media is the low gas mobility caused by the oil components and the high viscosity. High resin and asphaltene concentrations and the high viscosity of Orinoco belt heavy oil increase the stability of bubble films and prevent gas breakthrough in the oil phase, which forms a continuous gas, compared with the solution-gas drive of light oil. The increase in the gas relative permeability with temperature is caused by higher interfacial tensions and the bubble-coalescence rate at high temperatures. The experimental results can provide theoretical support for foamy-oil production.

Coreflooding and Pore-Scale Visualization of Foamed Gel Flowed in Porous Network Media

To investigate the mechanisms of enhancing oil recovery and the flow behaviors of foamed gel in porous media, foamed gels with characteristics of excellent strength and viscosity were prepared with polymer, crosslinking agent, foam agent, and formation water. The breakthrough-vacuum method and a rotary viscometer were used to evaluate the strength and viscosity of foamed gel. Coreflooding and pore-level visualization experiments were performed in heterogeneous reservoir models. Laboratory results illustrate that high strength and viscosity of foamed gel can be prepared by 0.15% NJ-8, 0.2% polyacrylamide solution, and 1.5% foaming agent. The strength and viscosity of the foamed gel reached 0.06 MPa and 10,000 MPa · s, respectively. The results of coreflooding experiments in heterogeneous cores show that oil recovery can be improved by approximately 36.9% after injecting 0.3 pore volume of the foamed gel, and enhanced oil recovery is mainly attributed to the improving sweep efficiency of mid- to low-permeability layers. Images of visualization flooding demonstrate that foamed gel exhibits good oil resistance and elasticity when used with crude oil. Furthermore, the new amoeba effect, Jamin effect, fluid-diverting effect, and extruding effect between foamed gel and oil in porous media can enhance oil recovery by improving sweep efficiency.

Static and dynamic foam/oil interactions: Potential of CO2-philic surfactants as mobility control agents

Abstract Examination of the nature and extent of CO2 foam/oil interactions is essential for the successful design and application of surfactants in foam assisted water alternating gas (FAWAG) process. A structure–property relationship of surfactants based on theoretical method, static bulk tests, and dynamic displacements in porous media subjected to foam flooding is provided in this study. Surfactants with an increased affinity towards CO2 are intended to improve foam mobility control mechanism in a Malaysian oil reservoir. Two anionic foaming agent surfactants (in-house developed FomaxII and industry benchmark alpha olefin sulfonate (AOS)), and two CO2-philic surfactants (in-house developed FomaxVII and UTP-Foam) are selected to investigate the effect of surfactant tail groups on the phase interactions in a system of CO2-oil-brine. The effect of surfactant presence on the CO2/water and oil/water interfaces under reservoir conditions is measured by using a high pressure, high temperature tensiometer. Surfactants with higher tolerance against oil are selected based on static stability column tests and the equilibrium spreading coefficients model. The surfactant alternated with gas (SAG) displacements are then conducted by using the selected CO2-philic surfactants dissolved in injection brine to study the interactions of foam and oil in porous media at the reservoir conditions. A relationship was observed between foam stability column tests and the prediction results of the spreading theory, which can be a useful preliminary screening of an oil-resistant foam. The performance of foam during injection of surfactants in sandstone cores was also supporting the preliminary screening results. However, it was shown to be dependent on different parameters (such as formation of macroemulsion once foam lamellae ruptures, and surfactant–rock surface interactions), which are not necessarily observed in the static tests results. Macroemulsion once formed hindered the performance of subsequent FomaxVII surfactant slugs to produce foam.

Study of displacement efficiency and flow behavior of foamed gel in non-homogeneous porous media.

Field trials have demonstrated that foamed gel is a very cost-effective technology for profile modification and water shut-off. However, the mechanisms of profile modification and flow behavior of foamed gel in non-homogeneous porous media are not yet well understood. In order to investigate these mechanisms and the interactions between foamed gel and oil in porous media, coreflooding and pore-scale visualization waterflooding experiments were performed in the laboratory. The results of the coreflooding experiment in non-homogeneous porous media showed that the displacement efficiency improved by approximately 30% after injecting a 0.3 pore volume of foamed gel, and was proportional to the pore volumes of the injected foamed gel. Additionally, the mid-high permeability zone can be selectively plugged by foamed gel, and then oil located in the low permeability zone will be displaced. The visualization images demonstrated that the amoeba effect and Jamin effect are the main mechanisms for enhancing oil recovery by foamed gel. Compared with conventional gel, a unique benefit of foamed gel is that it can pass through micropores by transforming into arbitrary shapes without rupturing, this phenomenon has been named the amoeba effect. Additionally, the stability of foam in the presence of crude oil also was investigated. Image and statistical analysis showed that these foams boast excellent oil resistance and elasticity, which allows them to work deep within formations.

Dynamic Pore Scale Modeling of Asphaltene Deposition in Porous Media

Asphaltene deposition in porous medium is one of important factors in reducing the productivity of oil reservoirs. Reduction of permeability is the main factor, which is also due to reduced pores size or complete closure of them. The authors simulate phase one flow of oil in porous medium using a dynamic pore scale network model. Also asphaltene deposition process is considered based on a scaling equation. Because the greatest amount of precipitation occurs at bubble point pressure condition, we considered boundary conditions of the model in this pressure. The hypothetical model is only a very small element of a real reservoir rock therefore we assumed constant temperature in this process, consequently the main reason of asphaltene precipitation is pressure changes in the pores. Permeability reduction simulated was based on these steps: pore and throat pressure changes were due to fluid flow through the network and asphaltene deposited according to scaling equation. Applying a material balance for each pore/throat gives the volume reduction of pores/throats according to the deposited asphaltene. Due to this change in pores size permeability and porosity of the model is calculated. Repeating these steps over the time gives effect of asphaltene deposition on the primary properties of porous medium.

Shear modulus of heavy oils: Confinement effects in rheometer measurements

Abstract Viscosity of heavy oil constitutes an important property that governs the productivity of these reservoirs. The viscosity of these crude oils is highly dependent on many variables like temperature, frequency, and strain amplitude. In this paper we show that viscosity measurements of heavy oils can also depend on a measurement variable like the gap thickness in a parallel plate rheometer. In this paper we measured how the confinement of heavy oils between parallel plates induces an increase in shear modulus. We propose that the increase in shear modulus can be linked to the surface-active nature of heavy oils that can cause re-orientation of the molecules at the surface of the plates and producing a measurable increase in the shear modulus. The findings were observed in three different samples of heavy oils. The results of this work have major implications in the measurement of viscosity of heavy oils but more importantly in the flow of heavy oils in porous media.

The potential applications in oil recovery with silica nanoparticle and polyvinyl alcohol stabilized emulsion

Abstract We investigated the use of silica nanoparticle-stabilized emulsions to displace oil in porous media. A low-quality (20%) n-decane-in-water emulsion was injected into a glass-bead pack containing mineral oil under residual oil saturation conditions. Continuous injection of the emulsion caused steady trapping and accumulation of emulsion droplets, which occurred despite the fact that the bead sizes were 250–500 µm, whereas the average droplet size was ~30 µm, as indicated by particle size analysis. By alternately injecting small banks of emulsion (0.1 pore volume (PV)) and water (0.23−0.1 PV), the extent of emulsion droplet trapping could be controlled while achieving oil recovery. The effects of salt addition and polyvinyl alcohol (PVA)/nanoparticle concentration were also investigated in terms of emulsion stability and oil recovery. The salt addition (1 wt%) more efficiently stabilized the droplets without significant coalescence and contributed to approximately 4% more oil recovery than achieved in the absence of an emulsion system. The PVA/nanoparticle concentration indicated that the emulsion with a low concentration (0.05 wt%) of PVA and a high concentration (3 wt%) of nanoparticles had greater stability and enhanced oil recovery compared with the opposite (a high concentration (0.2 wt%) of PVA and low concentration (1 wt%) of nanoparticles). These results indicated that the addition of salt and PVA/nanoparticle concentration influenced oil recovery and emulsion stability. Oil recovery was related to emulsion stability.