Nonwetting Phase Research Articles

Extreme capillary heterogeneities and in situ fluid compartmentalization due to clusters of deformation bands in sandstones

Previous work has shown that individual deformation bands act like capillary barriers and influence fluid saturation. More common in nature, however, are clusters of deformation bands that form complex three dimensional geometries. The aim of this study is to analyze the extent and mechanisms of fluid compartmentalization due to clustered bands. Drainage multiphase fluid flow experiments were performed on a Navajo sandstone core sample characterized by diversely oriented clusters of deformation bands, that sub-divide the host rock into several compartments. Medical X-ray CT images were acquired while nitrogen was injected at progressively higher flow rates into a water-saturated core during transient and steady-state conditions. Spatial and temporal analyses of the non-wetting phase plume migration suggest that deformation bands act like capillary barriers and contribute to the development of an extremely tortuous saturation front. Differential pressure behavior across the core is linked to the breakthrough of N2 into the individual compartments, resulting in highly variable N2 saturation throughout the experiment. Migration into downstream compartments occurs via the exceedance of capillary entry pressure in portions of the bands. Simulation models of simplified systems demonstrate that capillary end effects and discontinuities in the deformation bands impact fluid saturation. The experiments and models presented here show that clusters of deformation bands have the potential to strongly compartmentalize a sandstone reservoir. Hence, prior analysis of the geometry of deformation band structures in a reservoir could significantly reduce the risk of overestimating reservoir capacity, and improve predictions of fluid mobility.

The development of intermittent multiphase fluid flow pathways through a porous rock

Intermittent fluid flow has recently been identified as an important transport mode for processes involving subsurface multiphase fluids such as CO2 storage and natural gas production. However, due to experimental limitations, it has not been possible to identify why intermittency occurs at subsurface conditions and what the implications are for upscaled flow properties such as relative permeability. We address these questions with observations of nitrogen and brine flowing at steady-state through a carbonate rock. We overcome previous imaging limitations with high-speed (1s resolution), synchrotron-based X-ray micro-computed tomography combined with pressure measurements recorded while controlling fluid flux. We observe that intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores, which would not be possible with connected pathway flow alone for the same flow rate. The volume of fluid intermittently fluctuating increases with capillary number, with the corresponding expansion of the flow network minimising the role of inertial forces in controlling flow even as the flow rate increases. Intermittent pathway flow sits energetically between laminar and turbulent through connected pathways. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers where the pore geometry controls the location of intermittency. However, as the capillary number increases further, the role of pore structure in controlling intermittency decreases which corresponds to an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and the upscaled manifestation in relative permeability.

Investigation on droplet dynamic snap-off process in a short, abrupt constriction

Droplet snap off is one of the most usual phenomena in oil recovery during water injection in water-wet porous media. In this work, the droplet dynamic snap-off process in a short, abrupt constriction is investigated. Three different phenomena, i.e. total breakup, partial breakup and non-breakup, of the nonwetting phase droplets are observed, the flow characteristics of droplets in each phenomenon and relevant physical mechanisms are analyzed. We find that both the initial size and velocity of the droplet greatly influence the breakup process. The viscosity of droplet also affects the breakup state. The critical conditions of each phenomenon are obtained based on dimensionless droplet size and capillary number, which could be used to predict the droplet breakup state. Under a certain capillary number, daughter droplet distribution is influenced by initial droplet size.

Dynamic fluid configurations in steady-state two-phase flow in Bentheimer sandstone.

Fast synchrotron tomography is used to study the impact of capillary number, Ca, on fluid configurations in steady-state two-phase flow in porous media. Brine and n-decane were co-injected at fixed fractional flow, f_{w}=0.5, in a cylindrical Bentheimer sandstone sample for a range of capillary numbers 2.1×10^{-7}≤Ca≤4.2×10^{-5}, while monitoring the pressure differential. As we have demonstrated in Gao etal. [Phys. Rev. Fluids 5, 013801 (2020)2469-990X10.1103/PhysRevFluids.5.013801], dependent on Ca, different flow regimes have been identified: at low Ca only fixed flow pathways exist, while after a certain threshold dynamic effects are observed resulting in intermittent fluctuations in fluid distribution which alter fluid connectivity. Additionally, the flow paths, for each capillary number, were imaged multiple times to quantify the less frequent changes in fluid occupancy, happening over timescales longer than the duration of our scans (40s). In this paper we demonstrate how dynamic connectivity results from the interaction between oil ganglia populations. At low Ca connected pathways of ganglia are fixed with time-independent small, medium, and large ganglia populations. However, with an increase in Ca we see fluctuations in the size and numbers of the larger ganglia. With the onset of intermittency, fluctuations occur mainly in pores and throats of intermediate size. When Ca is further increased, we see rapid changes in occupancy in pores of all size. By combining observations on pressure fluctuations and flow regimes at various capillary numbers, we summarize a phase diagram over a range of capillary numbers for the wetting and nonwetting phases, Ca_{w} and Ca_{nw}, respectively, to quantify the degree of intermittent flow. These different regimes are controlled by a competition between viscous forces on the flowing fluids and the capillary forces acting in the complex pore space. Furthermore, we plot the phase diagrams of the transition from Darcy flow to intermittent flow over a range of Reynolds and Weber numbers for the wetting and nonwetting phases to evaluate the balance among capillary, viscous, and inertial forces, incorporating data from the literature. We demonstrate that pore geometry has a significant control on flow regime.

PFG NMR time-dependent diffusion coefficient analysis of confined emulsion: Post drainage phase conformation

In this work, we present a characterization of phase configuration in water-saturated sintered glass bead samples after oil injection, through the analysis of time-dependent diffusion coefficients obtained from sets of one-dimensional pulsed field gradient nuclear magnetic resonance (PFG NMR) measurements, pre and post drainage. Estimates of samples' surface-to-volume ratio and permeability from pre drainage PFG measurements in a water-saturated sample were compared with analytical and reported values, respectively, and a fair agreement was found in both cases. Short-time analysis of diffusion coefficients extracted from PFG measurements was used to quantify the increase in surface-to-volume ratio probed by the wetting phase after drainage. Analysis of water and oil diffusion coefficients from post drainage PFG experiments were carried out using a bi-Gaussian model, and two distinct scenarios were considered to describe fluids conformation within pores. For the case where non-wetting phase was considered to exhibit a poorly connected geometry, an analysis assuming the formation of oil-in-water droplets within pores was performed, and a Gaussian distribution of droplets radii was determined.

GAS–WATER RELATIVE PERMEABILITIES FRACTAL MODEL IN DUAL-WETTABILITY MULTISCALE SHALE POROUS MEDIA DURING INJECTED WATER SPONTANEOUS IMBIBITION AND FLOW BACK PROCESS

The multiphase flow behavior in shale porous media is known to be affected by multiscale pore size, dual surface wettability, and nanoscale transport mechanisms. However, it has not been fully understood so far. In this study, fractal model of gas–water relative permeabilities (RP) in dual-wettability shale porous media for both injected water spontaneous imbibition and the flow back process are proposed using fractal geometry. The shale pore structure is described as tortuous with different pore sizes and morphologies including slit pore, equilateral triangle, circular pore and square pore. The proportion of each pore morphology can be obtained from SEM/FIB-SEM pore structure characterization results. Injected water spontaneous imbibition after hydraulic fracturing is modeled as the capillary force dominated process and injected water flow back is modeled as a non-wetting gas phase drainage process in inorganic matter. The organic pores are deemed to be not accessible by injected water. The boundary slip of water and free gas flow in the inorganic matrix are considered while both free gas flow and adsorbed gas flow are modeled in organic matter. The proposed gas–water RP fractal model is verified via comparisons with the available experimental data and is discussed in detail. Study results reveal that gas phase RP increases with increasing pore fractal dimensions and tortuosity fractal dimensions, whereas it decreases with increasing Total Organic Carbon (TOC) volumes. Water phase RP decreases with increasing of pore fractal dimensions and tortuosity fractal dimensions, whereas it increases with increasing TOC volumes.

Pore‐Scale Modeling of Drainage Displacement Patterns in Association With Geological Sequestration of CO2

AbstractWe investigate the immiscible displacement (drainage) of a wetting fluid in a porous medium by a nonwetting fluid using multi–graphics processing unit (GPU) lattice Boltzmann simulations with the aim of better understanding the pore‐scale processes involved in the geological sequestration of CO2. Correctly resolving the dynamics involved in multiphase flow in permeable media is of paramount importance for any numerical scheme. Generally, the average fluid flow is assumed to be at low Reynolds numbers Reav. Hence, by neglecting inertial effects, this immiscible displacement should be characterized by just two dimensionless numbers, namely, the capillary number Caav and the viscosity ratio, which quantify the ratio of the relevant forces, that is, the viscous and capillary forces. Our investigation reveals that inertial effects cannot be neglected in the range of typical capillary numbers associated with multiphase flow in permeable media. Even as the average Caav and Reav decrease away from the injection point, inertial effects remain important over a transient amount of time during abrupt Haines jumps, when the nonwetting phase passes from a narrow restriction to a wider pore space. The local Rel at the jump sites is orders of magnitude higher than the average Reav, with the local dynamics being decoupled from the externally imposed flow rate. Therefore, a full Navier‐Stokes solver should be used for investigating pore‐scale displacement processes. Using the Ohnesorge number to restrict the parameter selection process is essential, as this dimensionless number links Caav and Reav and reflects the thermophysical properties of a given system under investigation.

Influence of fractal surface roughness on multiphase flow behavior: Lattice Boltzmann simulation

Accurate characterization of surface roughness and understanding its influence on multiphase flow behavior are important for industrial and environmental applications such as enhanced oil recovery, CO2 geological sequestration, and remediation of contaminated aquifers. Although some experimental and simulation studies have been conducted for investigating surface roughness in regular geometry structures, a more realistic description of roughness and its quantitative influence on multiphase flow need to be further explored. In this study, an optimized color-gradient lattice Boltzmann model is applied to simulate the steady-state two-phase flow in two-dimensional porous media modeled by a fourth-order Sierpinski carpet. The model is validated by comparing with the analytical solution and literature results, indicating reliability of our method. Then, rough surfaces with different roughness height and surface fractal dimension are characterized by a modified Weierstrass-Mandelbrot function and these effects on two-phase flow are investigated systematically by our model. The results show that the surface roughness has a negative effect on single-phase and two-phase fluid flow, which implies that the absolute and relative permeabilities for both wetting phase and nonwetting phase decreases with the increase of roughness height or surface fractal dimension. In addition, the surface roughness has influence on the two-phase distribution, velocity distribution and fluid-fluid/fluid-solid interface area, especially under the neutral wetting condition. Our study provides a pore-scale insight into the effect of surface roughness on two-phase flow, which is important for a fundamental understanding on macroscopic multiphase flow behaviors.

Experimental investigation of different brines imbibition influences on co- and counter-current oil flows in carbonate reservoirs

Imbibition of water, as wetting phase in oil-wet fractured carbonate reservoirs, plays a key role in fluid flow between matrix and fracture system. The type of injected seawater and its chemistry would profoundly influence the imbibition process. In this study, the impact of smart water (a brine that its ions have been adjusted to facilitate oil recovery) and low salinity water on co- and counter-current imbibition processes for oil-wet carbonate cores has been experimentally investigated. The results show an increase of about 10% in oil recovery for co- and counter-currents for smart seawater imbibition compared to that of low salinity seawater. In addition, as a result of the influence of co- and counter-current on each other, by co-current removal from one core face, the counter-current in the other face would be intensified by as much as about 75%. A close examination of different lengths (5, 7 and 9 cm) of carbonate cores with the same permeability revealed that by decreasing porous medium length, the amount of counter-current producing oil would be decreased so that in the 5 cm core, counter current oil production will not happen. For similar core lengths by increasing permeability, the share of counter current flow would be decreased approximately 18% since the capillary pressure could not overcome non-wetting phase viscous forces. Considering the role of matrix length along with a modified brine (which is designed according to the matrix mixture) strengthen the relevant mechanisms to have more oil production so that the higher thickness of matrix causes the higher amount of co-current oil producing and consequently more total recovery.

Computational Optimization of Porous Structures for Electrochemical Processes

Porous structures are naturally involved in electrochemical processes. The specific architectures of the available porous materials, as well as their physical properties, crucially affect their applications, e.g., their use in fuel cells, batteries, or electrolysers. A key point is the correlation of transport properties (mass, heat, and charges) in the spatially—and in certain cases also temporally—distributed pore structure. In this paper, we use mathematical modeling to investigate the impact of the pore structure on the distribution of wetting and non-wetting phases in porous transport layers used in water electrolysis. We present and discuss the potential of pore network models and an upscaling strategy for the simulation of the saturation of the pore space with liquid and gas, as well as the computation of the relative permeabilities and oxygen dissolution and diffusion. It is studied how a change of structure, i.e., the spatial grading of the pore size distribution and porosity, change the transport properties. Several situations are investigated, including a vertical gradient ranging from small to large pore sizes and vice versa, as well as a dual-porosity network. The simulation results indicate that the specific porous structure has a significant impact on the spatial distribution of species and their respective relative permeabilities. In more detail, it is found that the continuous increase of pore sizes from the catalyst layer side towards the water inlet interface yields the best transport properties among the investigated pore networks. This outcome could be useful for the development of grading strategies, specifically for material optimization for improved transport kinetics in water electrolyser applications and for electrochemical processes in general.

Pore-to-Core Upscaling of Solute Transport Under Steady-State Two-Phase Flow Conditions Using Dynamic Pore Network Modeling Approach

We present a solute transport model, developed by employing a dynamic pore network modeling approach, to investigate dispersive solute transport behaviors in consolidated porous media. The model is capable of upscaling solute transport processes from pore to core, under two-phase fluid configurations. The governing equations of fluid flow, fluid displacement, and solute transport are solved at the pore level. A heavily parallelized computing scheme is utilized to simulate dynamic fluid displacements and transport processes in a core-scale pore network constructed from micro-computed tomography (micro-CT) images of a Berea sandstone sample. A series of solute transport simulations are conducted under the single-phase condition to validate the model by comparing the computed longitudinal dispersion coefficients against the experimental data over a wide range of Peclet numbers (Pe), i.e., $$3 \times 10^{-2}{\sim}3 \times 10^5$$ . The model is then used to simulate solute transport under two-phase fluid configurations to examine the effects of the non-wetting phase saturation on solute transport behaviors. More specifically, solute transport is studied at different Pe and different water saturations obtained at the end of imbibition processes. We find that in a two-phase system, the longitudinal dispersion coefficient substantially increases with enhanced convective mixing under the transport regime with high Pe but decreases with restricted diffusive mixing at low Pe. In addition, the results indicate a non-monotonic dispersion–saturation relation under the convective transport condition. We illustrate that a strong correlation exists between the extent of dispersive mixing and the heterogeneity of fluid saturation profile across a core-scale network.

In Situ Characterization of Three‐Phase Flow in Mixed‐Wet Porous Media Using Synchrotron Imaging

AbstractWe use fast synchrotron X‐ray microtomography to understand three‐phase flow in mixed‐wet porous media to design either enhanced permeability or capillary trapping. The dynamics of these phenomena are of key importance in subsurface hydrology, carbon dioxide storage, oil recovery, food and drug manufacturing, and chemical reactors. We study the dynamics of a water‐gas‐water injection sequence in a mixed‐wet carbonate rock. During the initial waterflooding, water displaced oil from pores of all size, indicating a mixed‐wet system with local contact angles both above and below 90°. When gas was injected, gas displaced oil preferentially with negligible displacement of water. This behavior is explained in terms of the gas pressure needed for invasion. Overall, gas behaved as the most nonwetting phase with oil as the most wetting phase; however, pores of all size were occupied by oil, water, and gas, as a signature of mixed‐wet media. Thick oil wetting layers were observed, which increased oil connectivity and facilitated its flow during gas injection. A chase waterflooding resulted in additional oil flow, while gas was trapped by oil and water. Furthermore, we quantified the evolution of the surface areas and both Gaussian and the total curvature, from which capillary pressure could be estimated. These quantities are related to the Minkowski functionals which quantify the degree of connectivity and trapping. The combination of water and gas injection, under mixed‐wet immiscible conditions, leads to both favorable oil flow and significant trapping of gas, which is advantageous for storage applications.

Hydrate is a Nonwetting Phase in Porous Media

AbstractIn porous media containing gas hydrate, the hydrate morphology impacts the flow behavior of the fluid phases. We hypothesize that hydrate emplaces itself as a nonwetting phase and use this idea to describe relative permeability of water in a hydrate/water system. We perform steady‐state relative permeability measurements in hydrate‐bearing samples with a range of hydrate saturation. We measure and compare water relative permeability in the presence of gas and in the presence of hydrate and find that the water relative permeability is the same in both cases. This suggests that (1) relative permeability for hydrate systems can be obtained without performing difficult experiments on hydrate bearing sediments, (2) flow properties are porous‐media dependent, and (3) models that assume a fixed pore or tube geometry are inadequate.

A 6M digital twin for modeling and simulation in subsurface reservoirs

A 6M digital twin for modeling and simulation in subsurface reservoirs

Experimental Investigation of the Effect of Adding Nanoparticles to Polymer Flooding in Water-Wet Micromodels.

Recently, the combination of conventional chemical methods for enhanced oil recovery (EOR) and nanotechnology has received lots of attention. This experimental study explores the dynamic changes in the oil configuration due to the addition of nanoparticles (NPs) to biopolymer flooding. The tests were performed in water-wet micromodels using Xanthan Gum and Scleroglucan, and silica-based NPs in a secondary mode. The microfluidic setup was integrated with a microscope to capture the micro-scale fluid configurations. The change in saturation, connectivity, and cluster size distributions of the non-wetting phase was evaluated by means of image analysis. The biopolymer content did not affect the ability of the NPs to reduce the interfacial tension. The experiments showed that the reference nanofluid (NF) flood led to the highest ultimate oil recovery, compared to the Xanthan Gum, Scleroglucan and brine flooding at the same capillary number. In the cases of adding NPs to the biopolymer solutions, NPs-assisted Xanthan flooding achieved the highest ultimate oil recovery. This behavior was also evident at a higher capillary number. The overall finding suggests a more homogenous dispersion of the NPs in the solution and a reduction in the polymer adsorption in the Xanthan Gum/NPs solution, which explains the improvement in the sweep efficiency and recovery factor.

A pore-scale experimental investigation of process-dependent capillary desaturation

A series of micro-scale core-flooding experiments were conducted in a miniature water-wet Berea sandstone sample to examine how changes in the desaturation (water-displacing-oil) protocol impact the non-wetting phase recovery and to provide, to the best of our knowledge, the first pore-scale evidences of the associated displacement subtleties. We studied (i) the continuous displacement mode (CDM), which consisted of a series of imbibition tests with increasing capillary numbers and similar initially connected oil, and (ii) the discontinuous displacement mode (DDM), which included a drainage followed by a multi-rate imbibition test. During all experiments, a cutting-edge imaging platform was employed to visualize the fluid occupancies in the pore space.The in-situ saturation measurements showed that, at a given capillary number, the non-wetting phase recovery was more efficient under the continuous mode during which the oil phase was connected prior to each imbibition. This is attributed to the changes in the order by which the pore-scale displacement events take place before entrapment. For the DDM, however, the entrainment of oil clusters is the governing recovery mechanism, and the desaturation process was observed only when a threshold capillary number was reached. These findings are supported by pore-scale fluid occupancy maps demonstrating piston-like and snap-off events during the capillary-driven flow processes as well as trapped cluster entrainment during the viscous-dominated flow tests. Moreover, this investigation presents previously unidentified pore-scale displacement events in natural porous media, such as fragmentation and coalescence of trapped non-wetting phase globules prior to entrainment.These mechanisms took place at intermediate capillary numbers and mostly under the discontinuous displacement mode before the threshold of mobilization was reached. The capillary desaturation process under CDM was found to be gradual and more pronounced compared to that under the DDM mode. It is also demonstrated that even though the pore-scale displacement mechanisms responsible for oil recovery are different for CDM and DDM, the viscous-dominated imbibition tests produce similar distributions of trapped oil clusters under both cases.

Impact of grain roughness on residual nonwetting phase cluster size distribution in packed columns of uniform spheres.

We imaged the pore-scale distribution of air and water within packed columns of glass spheres of different textures using x-ray microcomputed tomography after primary drainage and after secondary imbibition. Postimbibition residual air saturation increases with roughness size. Clusters larger than a critical size of about 15 to 40 pores are distributed according to a power law, with exponents ranging from τ=2.29±0.04 to 3.00±0.13 and displaying a weak negative correlation with roughness size. The largest cluster constitutes 7 to 20% of the total residual gas saturation, with no clear correlation with roughness size. These results imply that activities that enhance grain roughness by, e.g., creating acidic conditions in the subsurface, will promote capillary trapping of nonwetting phases under capillary-dominated conditions. Enhanced trapping, in turn, may be desirable in some engineering applications such as geological CO_{2} storage, but detrimental to others such as groundwater remediation and hydrocarbon recovery.

Dynamic capillary pressure analysis of tight sandstone based on digital rock model

In recent studies, dynamic capillary pressure has shown significant impacts on the flow behaviors in porous media under transient flow condition. However, the effect of dynamic capillary pressure effect on tight sandstone is still not very clear. Since lattice Boltzmann method (LBM) is a very promising and widely used method in analyzing flow behaviors, therefore, a two-phase D3Q27 LBM model is adopted in this paper to simulate the flow behaviors and analyze the dynamic capillary pressure effect in tight sandstone. Moreover, a new pore segmentation method for tight sandstone base on U-net deep learning model is implemented in this study to improve the pore boundary qualities of pore space, which is crucial for two-phase LBM simulation of tight sandstone. A total of 3800 3D sub-volume data sets extracted from computed tomography data of 19 tight sandstone samples are selected as ground truth data to train the network and segment the pore space afterward. The simulation results based on the segmented digital rock model, show that nonwetting phase fluid prefer the path with lower dynamic capillary pressure in the seepage process before breaking through the porous model. Furthermore, the increase of injection rate causes the saturation changes more quickly, injection rate also shows apparent positive correlation relationship with capillary pressure, which implies that dynamic capillary pressure effect also exists in tight sandstone, and LBM based two-phase flow simulation could be used to quantitatively analyze such effect in tight sandstone. Cited as : Cao, Y., Tang, M., Zhang, Q., Tang, J., Lu, S. Dynamic capillary pressure analysis of tight sandstone based on digital rock model. Capillarity, 2020, 3(2): 28-35, doi: 10.46690/capi.2020.02.02

Exchange flow numerical method of dual-porosity model for different matrix size in 2D oil-water imbibition

Spontaneous imbibition is a common natural phenomenon in porous media. For natural fractured reservoir with a large number of hydrophilic and oleo-phobic rock blocks, the imbibition displacement of non-wetting phase by wetting phase with the dominant effect of capillary force is an important mechanism in exchange flow between matrix block and fracture in reservoir recovery. Scientists have concluded a scaling model which includes the permeability, porosity, boundary conditions, fluid-solid interaction and other factors though lots of experiments. In this study, after proposing appropriate characteristic scale in different periods of imbibition, the approximate saturation solution in one-dimensional imbibition obtained on the basis of scaling model is extended to two-dimensional process. Then, the exchange flow numerical method of dual-porosity model for two-dimensional multiphase imbibition is obtained. The results of simulation example show that the numerical method of exchange flow in this paper is more accurate than that of traditional dual-porosity model under different matrix rock size.

CO2 flooding enhanced oil recovery evaluated using magnetic resonance imaging technique

CO2 flooding is an efficient enhanced oil recovery method, especially for waterflooding depleted reservoirs. In this work, waterflooding and CO2 flooding were evaluated in a coreflooding experiment using MRI to clarify the multiphase flow and oil recovery behavior in porous rock at a typical reservoir temperature-pressure condition. A series of in situ spatially and temporally resolved MR images revealed dynamic distribution information of oil, water, and sc-CO2 during coreflooding process. For waterflooding, the phenomenon of water viscous fingering and channelling were obvious, which affected the volumetric sweep efficiency, higher water injection rate may appropriately improve oil recovery but the EOR efficiency was lower. CO2 diffused and migrated into some regions where was not efficiently swept by waterflooding, and a CO2-oil-miscible phase was formed. The formed local ‘oil bank’ before sc-CO2 front restrained effectively CO2 channelling and fingering, and enhanced oil recovery by 13.2% and generated more homogeneous residual oil saturation distribution in porous media compared to waterflooding. The relative permeability and capillary pressure were determined simultaneously based on the capillary end oil saturation profiles, these quantitative results demonstrated that CO2 flooding expanded fluids mobility range of the wetting and nonwetting phases and improved the displacement efficiency about 10% than waterflooding.