Heavy Oil Displacement Research Articles

Consideration of geomechanic effects during hydrodynamic model of weakly-cemented reservoir setting

The article offers an approach to tuning of heavy oil deposition model from weakly-cemented reservoir with geomechanic effects. This effects appear as changing permeability at the downhole zone near the injection well. Researchers think that the nature of low-density zones occurrence related to increasing of the resistance factor which is influenced with increasing of filtration velocity. High filtration velocity is caused by polymer flooding increasing. This work was made with basis on hydrodynamic model of the pilot area where are the experiments of displacement of heavy oil during polymer flooding. There are not only well history-matching but assessment of hydrodynamic model prediction ability. Keeping of geomechanic effects allows to achieve the adequate reproduction dynamic of fact bottom-hole pressure during polymer solution injection. Application of the given approach leads to uncertainty reduction and improved prediction reliability.

MODEL-BASED ANALYSIS TO EVALUATE THE EFFECT OF POLYMER PROPERTIES AND PHYSICAL PHENOMENA ON POLYMER FLOODING OPERATIONS

Polymer flooding, known for enhancing heavy oil displacement, may encounter efficiency-limiting physical phenomena. This work assesses the impact of key factors like viscosity, shear rate, and adsorption in field applications using a model-based approach on the EPIC001 case, a real offshore Brazilian heavy oil reservoir. In simulation results, increasing the displacing fluid viscosity using apparent or zero-shear functions, oil production and economic returns show improvements over waterflooding. The shear rate effect slightly increases oil production and enhances injectivity loss due to shear-thinning in polymer flow. However, modeling it increases computation costs, as it extends simulation run time from minutes to days, making it impractical for intensive processes like production optimization. An analysis of the method’s effectiveness shows that it varies based on the adsorption level considered. At its highest value, even with a higher oil recovery factor, the economic return was lower than using waterflooding. Combining shear rate and adsorption has a minimal impact on field indicators when compared to adsorption alone. This work enhances the comprehension of physical phenomena and non-Newtonian behavior in tertiary polymer flooding on heavy oil reservoirs and its impact on the production forecast. It also highlights important considerations for modeling-based procedures.

Offshore heavy oil displacement using water flooding - flow characteristics and efficiency

Offshore heavy oil displacement using water flooding - flow characteristics and efficiency

Experimental investigation on the effect of interfacial properties of chemical flooding for enhanced heavy oil recovery

Chemical compound flooding has demonstrated its efficacy in enhancing light oil recovery through ultra-low interfacial tension (IFT). However, the optimization of chemical systems properties for displacing heavy oil has not been clarified. This research aims to address this problem by designing common polymer and three surfactant-polymer (SP) systems with varying IFT and interfacial viscoelasticity behaviors, and comparing their ability to recover heavy oil. The findings of core flooding tests indicate that the system with low IFT and high interfacial viscoelasticity simultaneously has a better displacement efficiency for heavy oil than other flood systems, which could enhance heavy oil recovery by 21.94%. Micro-model tests reveal the underlying mechanisms driving the enhanced macro-scale oil recovery. The emulsion formation and interface expansion facilitated by low IFT, as well as increased emulsion stability and reduced snap-off of oil droplets due to the presence of an elastic oil-water interfacial film. These phenomena is more capable of driving microscopic heterogeneous remaining oil and film remaining oil than other solution. The comparative experiment analysis shows that the difference in chemical flooding between heavy oil and light oil is caused by the discrepant distributions of surfactants at the oil-water interface. The light oil interface is a monolayer surfactant molecular film, the heavy components and surfactant moleculars exhibit both competitive and cooperative adsorption phenomena at the oil-water interface. The occurrence of viscosity reduction and increased emulsion stability are more influential factors in the process of heavy oil displacement than those of conventional ultra-low IFT systems used for light oil recovery.

Synthesis and evaluation of multi-aromatic ring copolymer as viscosity reducer for enhancing heavy oil recovery

Functional polymers play an increasingly significant role in oilfield development. Herein, the side-chain functionalized copolymer APVR was fabricated using functional monomer 2,6-bis(1-methyl-1H-benzo[d]imidazol-2-yl)pyridin-4-yl-methacrylate (BMP) with similar structure to the heavy components in crude oil and di-hexadecanol maleate (DHM) with long alkyl chain. 1H NMR, FTIR and TGA analyses were employed to characterize the structure of APVR. Simultaneously, viscosity reduction performance and heavy oil displacement performance of APVR were also studied. For comparison, the copolymers P(AAB), P(AAD) and P(AA) containing one functional monomer and without functional monomer were also synthesized. The results showed that when the copolymer concentration is 2000 mg/L, the viscosity reduction rate (VRR) of APVR, P(AAB), P(AAD) and P(AA) is 93.1%, 84.3%, 82.4% and 65.4%, respectively. Furthermore, compared with water flooding, their ultimate recovery of heavy oil increased by 18.34%, 13.78%, 13.18% and 9.93%. The interaction mechanisms between APVR and heavy oil were studied using XRD, SEM, and molecular dynamic simulation. Due to their unique structure, BMP and DHM were able to permeate into the molecule structures of heavy oil, reducing the intermolecular forces between heavy components by forming supramolecular forces with asphaltene. Thus, they led to the loose stacking of asphaltene aggregates, making it easier for APVR to emulsify oil droplets due to its amphiphilic property. The copolymer APVR shows promising potential for reducing heavy oil viscosity and may have broad application prospects in heavy oil exploitation.

Oil displacement performance and mechanism of Interfacially Active polymer (IAP)-Emulsifying viscosity Reducer (EVR) supramolecular compound system in heterogenous heavy oil reservoirs

Chemical Cold Heavy Oil Production (CCHOP) represents an effective approach to exploit heavy oil by injecting Oil Viscosity Reducer (OVR). However, the challenge lies in the crossflow of traditional OVR through high permeability channels in heterogeneous heavy oil reservoirs. a supramolecular compound system comprising Interfacially Active Polymer (IAP) and Emulsifying Viscosity Reducer (EVR) were proposed as a novel CHHOP agent to address this problem. A series of experiments were conducted to investigate the heavy oil displacement performance and mechanism of the IAP-EVR compound system, including assessments of heavy oil emulsification, emulsion stability, rheological properties, single-core oil displacement, and heterogeneous microscopic oil displacement. The results demonstrate that a stable O/W emulsion can be formed with the 0.1 wt% IAP-0.3 wt% EVR compound system under a low mixing rate of 200 rpm. The emulsion exhibits only an 8.0% dewatering rate and a low TSI value of 0.8. Moreover, the compound system effectively reduces the heavy oil viscosity from 1000 mPa·s to 325.7 mPa·s, facilitating the emulsification of the remaining oil after water flooding and enhancing its flowability, thus improving oil displacement efficiency. Additionally, the 0.1 wt% IAP-0.3 wt% EVR compound system increases the solution viscosity to 600 mPa·s, leading to a low W/O mobility ratio, which enhances the swept volume. Supramolecular association is identified as a crucial mechanism for stabilizing the emulsion and increasing the solution viscosity, as evidenced by a high elastic modulus of 144.7 mPa and a transition area observed in the viscosity-shear rate curve. In comparison to HPAM and IAP, the 0.1 wt% IAP-0.3 wt% EVR compound system yields higher oil recoveries of 21.84 %OOIP in the single core experiment. Moreover, noticeable emulsification is observed in the produced fluid, and oil recoveries of 89.85 %OOIP and 92.98 %OOIP are achieved in high and low permeable areas, respectively, in the heterogeneous microscopic model. These results indicate a mechanism that enhances both the swept volume and oil displacement efficiency. Overall, the findings of this study provide a laboratory foundation for the promising application of the IAP-EVR compound system in heterogeneous heavy oil reservoirs.

Evaluating the performance of designed terpolymers for polymer flooding

AbstractIn this work, polymeric materials designed for enhanced oil recovery (EOR) were evaluated for their intended application. Properties including viscosity, flow through porous media (resistance factor and residual resistance factor), and heavy oil displacement (incremental oil recovery) were assessed for designed terpolymers of 2‐acrylamido‐2‐methylpropane sulphonic acid (AMPS), acrylamide (AAm), and acrylic acid (AAc). The same properties were evaluated for two commercially available reference materials (e.g., partially hydrolyzed polyacrylamides or HPAM) with similar characteristics, which allowed for direct comparison between the newly designed terpolymers and materials that are currently on the market for the polymer flooding application. The incremental oil recovery directly associated with polymer flooding, which includes both the polymer flooding and post‐polymer waterflooding stages (excluding the initial waterflooding injection (or secondary) oil recovery), demonstrates that the designed terpolymers provided a higher incremental recovery (42% and 58%) than the reference materials (33% and 46%). Therefore, the terpolymers provided a higher contribution to incremental (or enhanced) oil recovery than the typical HPAM. Additionally, both designed terpolymers showed better injectivity in unconsolidated porous media and are less likely to cause plugging than the commercially available reference materials. Therefore, using a targeted design approach ultimately led to polymeric materials with excellent performance for EOR polymer flooding applications.

Numerical pore-scale simulation of propane injection for heavy oil displacement processes

Solvent injection processes offer a promising alternative to steam-based techniques for heavy oil recovery. Multiple mass transfer mechanisms, including interphase mass transfer, diffusion, and convection, would affect the process efficiency and recovery performance. Understanding the mass transfer processes in solvent-based heavy oil recovery processes is fundamental to accurately model the solvent/heavy oil interfacial dynamics and design efficient solvent recovery methods.A robust simulation framework based on the level-set method is proposed in this study to simulate the injection of a vaporized solvent (i.e., propane) into a bitumen-oil system. A pore-scale two-phase multi-component flow simulation is constructed. The solution of the Navier-Stokes equation is coupled with the level-set formulation to track the fluid/fluid interface; a concentration jump is applied to simulate the mass transfer across the gas-liquid interface. The model is validated against several bulk fluid systems where analytical solutions can be derived. Next, the model is tested using a more complex pore-scale system; a macro-scale mass transfer coefficient is estimated based on the linear mass transfer model. The values are compared to those described in the literature.The level-set simulation framework is useful for simulating multiphase multi-component interphase mass transfer in porous media. It serves as a tool to examine these different mechanisms' interactions and relative importance under various conditions. The proposed simulation framework can be readily applied to studying other subsurface processes, including carbon dioxide storage and groundwater flow.

Pore-Scale Displacement of Heavy Crude Oil During Low Salinity Water Flooding

Pore-Scale Displacement of Heavy Crude Oil During Low Salinity Water Flooding

Preparation and performance evaluation of a branched functional polymer for heavy oil recovery

To solve the problem of chromatographic separation encountered in surfactant–polymer composite systems, a branched functional polymer (PEM) was prepared from acrylamide, acrylic acid, polyethyleneimine, and a newly synthesized functional monomer (XN) to realize high efficient displacement of heavy oil in oil reservoir conditions. Proton nuclear magnetic resonance (1HNMR) analysis, elemental analysis, and Fourier-transform infrared spectroscopy verified the synthesis of PEM. The thickening performance, salt resistance, interfacial activity, ability of heavy oil viscosity reduction by emulsification, and core-flooding performance of PEM were systematically studied, with linear functional polymer PXM containing XN and conventional polymer HPAM as the control group. Under the synergistic effect of functional monomer XN and the branched structure, PEM demonstrated better thickening performance and more ideal heavy oil viscosity reduction compared with those of PXM and HPAM. The branched structure of PEM enhanced the interaction between molecules and the strength of the spatial network structure; notably, the thickening performance of PEM improved by 34.6% and 141.7%, and the salt resistance performance improved by 31.5% and 89.4%, compared with those of PXM and HPAM, respectively. Furthermore, PEM formed a relatively tight interfacial adsorption layer at the oil–water interface, leading to the reduction of interfacial tension. The heavy oil viscosity reduction rate of PEM (87.0%) was higher than that of PXM (79.5%). The emulsion formed was more stable than PXM, and the oil–water separation rate was slower. Owing to the better heavy oil viscosity reduction effect of PEM, the recovery factor of PEM (21.4%) was higher than that of PXM (17.2%) under the same polymer viscosity condition. These findings indicate that PEM and its functional mechanism are suitable for the enhancement of heavy oil recovery.

The Performance of Engineered Water Flooding to Enhance High Viscous Oil Recovery

Low salinity/engineered water injection is an effective enhanced oil recovery method, confirmed by many laboratory investigations. The success of this approach depends on different criteria such as oil, formation brine, injected fluid, and rock properties. The performance of this method in heavy oil formations has not been addressed yet. In this paper, data on heavy oil displacement by low salinity water were collected from the literature and the experiments conducted by our team. In our experiments, core flooding was conducted on an extra heavy oil sample to measure the incremental oil recovery due to the injected brine dilution and ions composition. Our experimental results showed that wettability alteration occurred during the core flooding as the main proposed mechanism of low salinity water. Still, this mechanism is not strong enough to overcome capillary forces in heavy oil reservoirs. Hence, weak microscopic sweep efficiency and high mobility ratio resulted in a small change in residual oil saturation. This point was also observed in other oil displacement tests reported in the literature. By analyzing our experiments and available data, it is concluded that the application of standalone low salinity/engineered water flooding is not effective for heavy oil formations where the oil viscosity is higher than 150 cp and high oil recovery is not expected. Hence, combining this EOR method with thermal approaches is recommended to reduce the oil viscosity and control the mobility ratio and viscous to capillary forces.

Viscous fingering during heavy-oil displacement by chemical solutions: Emulsion instability and partial-miscibility

The viscous fingering morphologies at a particular stage of emulsion displacements are observed to follow similar development patterns as that of the partially-miscible viscous fingering behavior (existent between the commonly studied fully miscible and immiscible systems). Chemically-induced viscous fingering before and after the finger droplet development resembling the partially-miscible fluid behavior is investigated using fractal dimensions and various -classic and modified-dimensionless scaling groups. We demonstrate, through the quantitative analysis using the empirical data collected from our previous experimental study, that the finger droplet formation morphologies observed in partially-miscible injection are indicative of an emulsion hydrodynamic instability behavior. The dominant parameters responsible for such droplet formation and their relationship to fractal dimension and hydrodynamic stability are mapped in a phase diagram with the original experimental images. • Emulsions from the droplet morphologies require an external force to maintain stability. • Emulsion stability is predominantly dependent on the viscosity force. • Low IFT is associated with the droplet generation after the initiation of the finger break. • Two types of “self-similar” behaviors per the categorization based on the saturation profiles. • Fractal dimension is proportional with surface tension and an inversely proportional to viscosity.

Study and Application of Heat Self-generated gases Flooding for Enhance Heavy Oil Recovery with Low-frequency High-power Harmonic Wave

Heat self-generated gases flooding with low-frequency high-power harmonic wave(LFHPHW) is a new technology combining of LFHPHW enhanced oil recovery, steam flooding, and gas flooding and so on. Its main mechanism is to improve the fluidity and reduce heavy oil viscosity and oil-water interfacial tension with self-generated gases (CO2, NH3, etc.). They can be further reduced by synergism effect with LFHPHW, which can improve the heavy oil fluidity and displacement efficiency to enhance heavy oil recovery. The results of this new technology show that it has many advantages and can enhance heavy oil recovery(EHOR).

Effect of Sodium Citrate and Calcium Ions on the Spontaneous Displacement of Heavy Oil from Quartz Surfaces

The dynamic displacement of heavy oil from solid surfaces by water plays a significant role in the oil recovery process. In this work, a bitumen-water-quartz system was applied to study the effect of sodium citrate and calcium ions on the dynamic displacement of bitumen from quartz surfaces. It was found that the addition of calcium ions slowed down the bitumen displacement rate and generated daughter droplets during the receding process. In contrast, the presence of sodium citrate not only accelerated the displacement of bitumen from quartz surfaces, but also led to a smaller contact angle at the end of the experiments. Moreover, calcium ions were chelated by the added sodium citrate, which counterbalanced the detrimental effect of calcium ions on the bitumen displacement. The reduced interfacial tension of bitumen-water interface and the increased negative charges on both bitumen and silica surfaces by sodium citrate were considered the reasons of the improved bitumen displacement process. To better understand the underlying physics, both the hydrodynamic model and molecular kinetic model were employed to analyze the dewetting dynamics of heavy oil from quartz surfaces under the effect of calcium ions and sodium citrate.

Physical Modeling of Oil Displacement in the Multifunctional Surfactant-based Chemical Composition

The paper presents the test results of a new multifunctional chemical composition based on surfactants in the process of displacement of heavy high-viscosity oil. Physical modeling of the oil displacement process was carried out in a laboratory setup which allows modeling heterogeneity of the oil-saturated formation. As a result of experiments it was found that the use of a multifunctional chemical oil-displacing composition based on a surfactant leads not only to a change in the filtration flows within the heterogeneous reservoir model but also to an increase in the oil displacement coefficient.

Dynamics of emulsion generation and stability during heavy oil displacement with chemicals and nanoparticles: Qualitative analysis using visual 2D data

There are a plethora of factors that may impact the viscous finger profiles observed in heavy oil-in-water emulsification in porous media such as chemical properties, chemical reaction, capillary number, mobility ratio, interfacial tension (IFT) gradient, chemical concentration, wettability, pH, and brine properties. To investigate such impact, we studied a large series of in-situ heavy oil-in-water emulsifications at various conditions using emulsifiers such as anionic surfactants, cationic surfactants, and NaOH (sodium hydroxide). For the stabilization of the emulsions formed with the emulsifiers, we tested nanofluids (silica, cellulose nanocrystal, zirconia, alumina) and polymers. 2-D visual results displayed that there exist finger profiles which strongly correlate with stable Winsor type 4 heavy oil-in-water emulsion generation along with “semi-stable” Winsor type 4 heavy oil-in-water emulsification. By controlling the structure of emulsion droplets and correlating observed multiple finger interactions to the materials, we enable the selection of novel designs for effective heavy-oil recovery as well as corresponding displacement mechanisms.

Displacement mechanism of polymeric surfactant in chemical cold flooding for heavy oil based on microscopic visualization experiments

In order to study the microscopic oil displacement mechanism of polymeric surfactant in chemical cold flooding for heavy oil, the indoor microscopic visualization displacement experiments were carried out. The flooding experiment of heavy oil was conducted by using water, osmotic modified oil displacing agent (a kind of polymeric surfactant) and water-in-oil emulsion (obtained by mixing polymeric surfactant and heavy oil) as displacing phases to study the mechanism of polymeric surfactant to enhance oil recovery in heavy oil reservoir. The experimental results show that the polymeric surfactant can increase the viscosity of the water phase, reduce the water-oil mobility ratio, expand the swept area, and there is no obvious fingering phenomenon which occurs during water flooding. The polymeric surfactant has the surfactant characteristics which can reduce the interfacial tension between oil and water to promote the formation of oil droplets with smaller droplet diameter. And the interfacial film composed of polymeric surfactant molecules will be formed on the surface of oil droplets to prevent the coalescence of oil droplets and improve the flow ability of oil phase. The water-in-oil emulsion can be miscible with the oil in heavy oil displacement process, and thus sweeps the areas such as the dead pores which cannot be swept by water and polymeric surfactant flooding, which increases the sweep efficiency to a certain extent. Cited as : Xu, F., Chen, Q., Ma, M., Wang, Y., Yu, F., Li, J. Displacement mechanism of polymeric surfactant in chemical cold flooding for heavy oil based on microscopic visualization experiments. Advances in Geo-Energy Research, 2020, 4(1): 77-85, doi: 10.26804/ager.2020.01.07

Dynamics of Changes in Composition and Stability of the Heavy Oil Sampled from the Usinskoye Oil Field as a Result of Formation Treatment with a Sol-Forming EOR System

The paper deals with a sol-forming system for oil recovery enhancement (EOR system) used to increase the rate of heavy oil displacement. The effect of sol-forming EOR system during the heavy oil displacement on the composition and stability of oil sampled from the Usinskoye oil field of Russia is investigated. The composition of a crude oil also plays an important role in changing its stability. The work is aimed to investigate stability of heavy crude oil in regards to asphaltene precipitation. For asphaltene toluene/n-heptane solutions, the aggregation stability of asphaltenes based on сhange in the optical density with time is investigated via spectrophotometry. SARA analysis is used to characterize the compositions of heavy oils. First, the content of asphaltenes precipitated from the oil samples is determined and then the samples of deasphalted crude oil (maltenes) are analyzed by the method of liquid adsorption chromatography for the purpose to study the composition of oil sampled from the wells before and after their treatment with the sol-forming EOR system. It is found out that the treatment of reservoir crude oil with the sol-forming EOR system results in changes in composition of saturated, aromatic hydrocarbons, resins, and asphaltenes (SARA components) and aggregative stability of produced oil. The results obtained showed that the aggregative stability of heavy oil depends not only on the content of SARA components in the dispersion medium but on the presence of metalloporphyrins in the oil. Metalloporphyrins could act as inhibitors of asphaltene precipitation, which is an additional factor responsible for the stabilization of the oil dispersed system

Effect of aluminium oxide nanoparticles on oilfield polyacrylamide: Rheology, interfacial tension, wettability and oil displacement studies

Polymers play an important role for oil recovery in reservoirs through the mechanism of improving mobility ratio and disproportionate permeability reduction. However, the efficiency of oilfield acrylamide polymer in reservoirs is limited because of saline brines and temperature conditions. Recently, due to their unique properties, nanoparticles (NP’s) are incorporated as additives to improve rheological properties of oilfield polyacrylamide. Nonetheless, previous studies have focussed solely on SiO2 nanoparticles. Herein, the use of metallic aluminium oxide nanoparticle was explored, exploited and evaluated. The morphology of the formulated polymeric nanofluids was determined using Fourier transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and temperature conditions was investigated. Moreover, interfacial tension (IFT) behaviour of the polymeric nanofluid at the oil/water interface was studied used Kruss tensiometer while wettability studies was carried out using goniometer. Comparative analysis was made between the shearing, IFT, and wettability behaviour of Al2O3 polymeric nanofluid, silica (SiO2) polymeric nanofluid, and base polymer without nanomaterial. Experimental result shows that inducing oilfield polyacrylamide with nanoparticles caused an enhancement of the rheological properties, and inhibited degradation of polymer molecules in the presence of hardness brine and temperature. At 2000 ppm HPAM solution (27 mol. % hydrolysis degree) and 0.1 wt% NP concentration, Al2O3 polymeric nanofluid exhibited better steady shear performance under the different electrolyte concentration and temperature conditions studied. Besides, IFT result shows the Al2O3 polymeric nanofluid lowers the IFT of the oil/water interface and alters the wettability of sandstone cores from oil-wet to water-wet condition. Finally, heavy oil displacement test in sandstone cores showed that oil recoveries of Al2O3 polymeric nanofluid had 10.6% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontiers of knowledge in nanomaterials application for EOR.

Simultaneous Occurrence of Miscible and Immiscible Displacement Processes During Solvent Displacement of Heavy Oil: A Parametric Analysis Using Visual Capillary-Tube Experiments

Summary Oil/solvent mixing is essential during solvent-injection applications to reduce the viscosity of oil, but mass transfer by diffusion becomes slower because the oil becomes heavier. Thus, an interface exists between the oil and solvent at certain times, being stronger in the beginning of the process. This results in an immiscible displacement controlled by the capillary forces while mixing is in progress. It is of practical and fundamental importance to determine the mechanisms responsible for the displacement of heavy oil and the behavior of solvents (acting as both immiscible and miscible displacement agents) because it could be advantageous to accelerate the dilution of heavy oil in many circumstances, including heterogeneous (fractured, layered, wormholed) systems. This is a complex process consisting of multiple pore phases (oil, solvent, their mixtures, and aqueous and vapor phases) at the same time, while different mechanisms such as capillary imbibition, miscible interaction (diffusion and convection), and gravity also act simultaneously. To investigate this complex phenomenon for different oil/solvent systems, a novel experimental method was used. The underlying mechanisms that dominate the solvent displacement process were comprehensively identified. The movement and evolution of interfaces among different fluid phases in glass capillary tubes were observed and recorded. Oil samples with different viscosities were used to examine the effects of oil viscosity on the mass transfer accelerated by imbibition transfer. The effects of temperature, wettability, and boundary conditions on the interaction of miscible fluid pairs were also studied. Pentane, heptane, and decane were used as the solvent phases. Advanced photographic techniques using ultraviolet (UV) light and dyed fluids were applied to better track the flow of different phases in the mixing zone. The experiments demonstrated a slowly smearing interface between the solvent and viscous oil. A unique natural convection was induced, with the combined effect of gravity, diffusion (mixing), and capillarity all contributing to the recovery of heavy oil. On the basis of the saturation method, boundary condition, and the Bond number, four different motion modes of mixing zone and interfaces of miscible fluids in the capillary tube were revealed and categorized to identify the degree of interface development (immiscible flooding). Also, the mixing zone, mass flux, and flow behavior were quantified using dimensionless parameters. The results indicate that priority may be given to a solvent with a high interfacial tension (IFT) for the solvent-based oil-recovery technique because of a strong imbibition and further enhancement of the dilution and displacement processes under conditions of a similar viscosity ratio. The data provided will be useful for the accuracy of modeling studies, especially for complex geologies where oil/solvent interaction is critically difficult to develop in order for mixing to occur.