Displacement In Porous Media Research Articles

Adaptive mesh refinement in locally conservative level set methods for multiphase fluid displacements in porous media

Multiphase flow in porous media often occurs with the formation and coalescence of fluid ganglia. Accurate predictions of such mechanisms in complex pore geometries require simulation models with local mass conservation and with the option to improve resolution in areas of interest. In this work, we incorporate patch-based, structured adaptive mesh refinement capabilities into a method for local volume conservation that describes the behaviour of disconnected fluid ganglia during level set simulations of capillary-controlled displacement in porous media. We validate the model against analytical solutions for three-phase fluid configurations in idealized pores containing gas, oil, and water, by modelling the intermediate-wet oil layers as separate domains with their volumes preserved. Both the pressures and volumes of disconnected ganglia converge to analytical values with increased refinement levels of the adaptive mesh. Favourable results from strong and weak scaling tests emphasize that the number of patches per processor and the total number of patches are important parameters for efficient parallel simulations with adaptive mesh refinement. Simulations of two-phase imbibition and three-phase gas invasion on segmented 3D images of water-wet sandstone show that adaptive mesh refinement has the highest impact on three-phase displacements, especially concerning the behaviour of the conserved, intermediate-wet phase.

Effects of Cassie-Wenzel wetting transition on two-phase flow in porous media

Wettability is one of the most important factors affecting multiphase flow in porous media. In this study, effects of the dynamic wetting process on two-phase flow displacement are investigated at the pore scale. A time-dependent Cassie-Wenzel wetting transition model is improved and incorporated into the pseudopotential multiphase multicomponent lattice Boltzmann model. With the Cassie-Wenzel wetting transition considered, two-phase flow displacement is simulated in Voronoi porous media with structural disorder and layered characteristics under different capillary number and wetting transition characteristic time. The simulation results show that the wetting transition promotes cooperative pore filling and weakens the effect of nonuniformity of capillary resistance. Under different capillary number, increased wetting transition rate improves the wettability of invading fluid, and thus the saturation of invading fluid is increased. The results also show that the layered structure with decreased pore size along the flow direction compacts the displacement pattern and weakens the viscous fingering, leading to higher displacement efficiency. While in this layered structure, effects of the wetting transition are suppressed due to lower interfacial length between the invading fluid and solid surface. The simulation results provide new insights of the influence of the dynamic wetting transition and on fluid displacement in porous media.

Influence of Nanofluid Flooding on Oil Displacement in Porous Media

Hydrocarbon displacement at the pore scale is mainly controlled by the wetness properties of the porous media. Consequently, several techniques including nanofluid flooding were implemented to manipulate the wetting behavior of the pore space in oil reservoirs. This study thus focuses on monitoring the displacement of oil from artificial glass porous media, as a representative for sandstone reservoirs, before and after nanofluid flooding. Experiments were conducted at various temperatures (25 – 50° C), nanoparticles concentrations (0.001 – 0.05 wt% SiO2 NPs), salinity (0.1 – 2 wt% NaCl), and flooding time. Images were taken via a high-resolution microscopic camera and analyzed to investigate the displacement of the oil at different conditions. In addition, contact angle measurements on quartz surfaces were also conducted at similar conditions to understand the flow behavior in the porous media. Further, zeta potential and particle size distribution measurements were conducted to examine the stability of the injected nanofluids. Results revealed that the injection of nanofluids into oil-wet pore space can significantly enhance the recovery rate of hydrocarbon by altering the wettability of the porous media. However, salinity, particularly at high nanoparticles concentration (≥ 0.005) can dramatically reduce the efficiency of nanofluid. Further, increased aging time can improve the ability of nanofluid to alter the wettability of the surface, and thus more oil can be displaced. Thus, nanofluid can efficiently enhance oil recovery if correctly formulated.

Pore-scale study of dynamic adsorption of a water-soluble catalyst during drainage displacement in porous media using lattice Boltzmann simulations

This paper presents the first systematic pore-scale study of the dynamic adsorption of a water-soluble catalyst during two-phase flows of immiscible fluids (water and oil) in porous media. The results of this paper are based on mathematical modeling in two-dimensional synthetic porous structures using the lattice Boltzmann simulations for two-phase flow and convective-diffusive transport of catalyst dissolved in a water that cannot penetrate the oil. The results showed that an increase in oil viscosity tends to a decrease in the maximum adsorbed amount of catalyst measured in a quasi-stationary state. An increase in capillary number, on the contrary, promotes an increase in the adsorbed amount. In this paper, for the first time, we have characterized the dynamic adsorption regimes versus the adsorption rate constant and capillary number. At a low adsorption rate, the adsorbed amount is determined by the duration of the reaction between the catalyst and the adsorbent particles, while at a high adsorption rate, the adsorbed amount is controlled by the maximum adsorption value. In addition, it has been established that a prediction accuracy of the adsorbed amount deteriorates significantly with decreasing capillary number.

Nondilute effects reshape miscible displacement in porous media

We provide an experimental benchmark for modeling nondilute miscible mixing in porous media, which emerges in CO${}_{2}$ sequestration and solvent-based enhanced oil recovery. In a near-fracture porous medium, we show that conventional Darcy-Fickian coupling fails to predict nondilute fluid-fluid displacement, although it works perfectly for dilute systems. Nondilute fluid systems show ``diffusive'' mixing kinetics, wedge-like mixing front, and significant convection at the front that is perpendicular to the concentration gradient. These above abnormal phenomena are rationalized by Korteweg stress, which is still challenging in modeling.

Contact Angle on Rough Curved Surfaces and Its Implications in Porous Media

The equilibrium contact angle depends on both the chemistry of the two fluids and solid base and the microstructure on the solid surface. Actual surface of the pore wall in porous media is typically rough and curved, which has not been well-considered in related applications. This work uses a free interfacial energy minimization approach to theoretically derive the equilibrium contact angle on two specific surface structures on flat surfaces and extends the derivation considering the surface curvatures in porous media. Results reveal that the equilibrium contact angle is not dependent on the curvature of spherical surfaces, and we further prove that this conclusion applies to any point along the apparent common line at solid surfaces with any arbitrary curvature. The fundamental physics is the local mechanical balance of a composite contact among three interfacial tensions. Furthermore, the contacting mode can shift from non-wetting to wetting when the pressure difference between two fluids exceeds the entry pressure of the microstructures, which should be considered in relative dynamic scenarios such as rain droplet impact and fluid displacement in porous media. Note that these conclusions are from pure theoretical analysis based on idealistic assumptions, and real circumstances may deviate from these assumptions.

Pore-scale study on miscible thermal displacing process in porous media using lattice Boltzmann method

A pore-scale investigation for a miscible thermal displacing process in porous media is performed in the present work using the lattice Boltzmann method. Particularly, the effects of viscous expansion coefficient βT and Lewis number Le on the displacing patterns and the residual rate σ are investigated. The numerical results show that the thermal displacement in porous media can be divided into four modes, i.e., one dominant displacement, conical displacement, local ramified displacement, and compact displacement. The prediction of the displacing modes for different values of βT and Le is summarized. Quantities analysis for characterizing thermal displacement indicates that σ in all simulation cases increases with βT, but the evolution trends of the residual rate for different Le are different. When βT>0, the residual rate σ decreases with the increasing Le, while for the cases with βT<0, the opposite is true. Furthermore, we found that σ changes obviously in the range of Le = 1–10, indicating that the thermal displacement mode can be easily changed by adjusting the thermal conductivity of the fluid to achieve different Lewis numbers of the system, thereby improving the displacement efficiency and displacement rate.

Effects of the Pore Morphology on Multiphase Fluid Displacement in Porous Media-A High-Resolution Modeling Investigation.

Advances in computational and image acquisition capabilities have made direct simulation of multiphase fluid flow through porous media possible. An example is application of volume of fluid modeling on images produced using the X-ray computed micro-tomography technique. Analysis of such high-resolution (both temporal and spatial) data sets provides new insights into pore-scale dynamics of previously less well-known processes. We present the outcomes of a high-resolution direct-simulation two-phase fluid displacement study performed on a series of five two-dimensional images of sandy porous media produced using erosion and dilation algorithms. This has enabled us to study the pore-scale dynamics systematically in models that are similar in connectivity but different in the morphology (pore sizes and aspect ratio). Our results show that the drainage and imbibition processes result in very distinct fluid displacement patterns in these models at the pore scale. As a result of drainage, the more open (eroded grains) models accommodate large oil clusters, while the tighter (dilated grains) models trap smaller oil clusters. The imbibition process is dominated by oil trapping in two ways: (i) bypassing larger oil clusters in the eroded models and (ii) local trapping of smaller clusters in the dilated models. This behavior is shown to arise from the relatively larger average aspect ratios of the dilated models compared to those of the eroded models. This promotes snap-off at pore throats (in competition with piston-like displacement), resulting in local trapping of the non-wetting phase. Both of these pore-scale trapping regimes seen here allow trapping of oil in as much as 50% of the pore space. Through the use of erosion and dilation operations, we show that a power-law relationship exists between the average pore size and the average grain size for these sandy media. This relationship is useful in designing engineered porous materials where pore sizes need to be estimated based on grain sizes.

Synthesizing CNT-TiO2 nanocomposite and experimental pore-scale displacement of crude oil during nanofluid flooding

Metallic nanoparticles and carbon nanomaterials have been extensively studied in enhanced oil recovery. Carbon nanotube (CNT)/TiO2 nanocomposite is synthesized and investigated in terms of contact angle, interfacial tension (IFT), emulsion stability, etc. Its performance in oil displacement in porous media is evaluated through glass micromodel experiment. The synthesized CNT/TiO2 is composed of TiO2-based nanocomposites and CNTs as reinforcement phase. TiO2 is the dominant crystalline phase, and TiO2 nanoparticles cover on the CNTs. CNT/TiO2 nanocomposite is able to alter the wetting conditions of the rock from strong oil-wet to hydrophilic conditions and effectively reduce the interfacial tension. CNT/TiO2 nanocomposite plays an effective role in stabilizing the Pickering emulsions, and even forms stable emulsions at high temperature as 90 °C. For NaCl concentration of up to 2%, a stable emulsion can be formed even after 7 days. It is observed from glass micromodel experiments that the CNT/TiO2 nanofluid provides a higher recovery factor denoting its promising performance in enhanced oil recovery.

Pore-scale modeling of multiphase flow in porous media using a conditional generative adversarial network (cGAN)

Multiphase flow in porous media is involved in various natural and industrial applications, including water infiltration into soils, carbon geosequestration, and underground hydrogen storage. Understanding the invasion morphology at the pore scale is critical for better prediction of flow properties at the continuum scale in partially saturated permeable media. The deep learning method, as a promising technique to estimate the flow transport processes in porous media, has gained significant attention. However, existing works have mainly focused on single-phase flow, whereas the capability of data-driven techniques has yet to be applied to the pore-scale modeling of fluid–fluid displacement in porous media. Here, the conditional generative adversarial network is applied for pore-scale modeling of multiphase flow in two-dimensional porous media. The network is trained based on a data set of porous media generated using a particle-deposition method, with the corresponding invasion morphologies after the displacement processes calculated using a recently developed interface tracking algorithm. The results demonstrate the capability of data-driven techniques in predicting both fluid saturation and spatial distribution. It is also shown that the method can be generalized to estimate fluid distribution under different wetting conditions and particle shapes. This work represents the first effort at the application of the deep learning method for pore-scale modeling of immiscible fluid displacement and highlights the strength of data-driven techniques for surrogate modeling of multiphase flow in porous media.

Impact of Wettability Alteration on the Front Instability of Immiscible Displacement in Porous Media

AbstractWettability alteration that occurs as a result of changing the brine composition or using chemicals that lower the interfacial tension can significantly alter the mobility of nonaqueous liquid (NAPL)/water phases. Here, we show that including dynamic wettability alternation (moving from non‐water‐wet to water‐wet) or interpolating between two sets of relative permeability curves may create an unstable displacement of the residence‐fluid by the injected fluid. The instability occurs due to not only the viscosity ratio but also the new shape of relative permeability curves and their end‐point values. We perform a full factorial design on Corey relative permeability parameters to determine the most destabilizing factors when the viscosity ratio is one. The observations indicate that instability proliferates when the end‐point relative permeability to the NAPL phase of modified salinity brine increases, and their corresponding exponents decrease compared with high salinity brine (seawater or formation water). Besides, numerical simulations of such a displacement demonstrate that modified salinity water (MSW)'s breakthrough is accelerated by wettability change toward water‐wet compared with a non‐fingering analytical solution. This may result in a delayed mobilization of the NAPL phase in porous media. We also discuss the role of capillary pressure, heterogeneity, and secondary and tertiary injection of MSW in stabilizing the shock front.

Hydrodynamics of gas-liquid displacement in porous media: Fingering pattern evolution at the breakthrough moment and the stable state

Gas-liquid displacement in porous media widely exists in many terrestrial/extraterrestrial subsurface resource extraction and utilization applications. The typical fingering displacement during gas invading has been well identified through extensive research efforts. Yet, the evolution of fingering structures after invading breakthrough is rarely reported. Herein, through a joint approach of experimental flow imaging and digital image processing, we investigated the gas-liquid fingering displacement in a porous-patterned microfluidic chip from the breakthrough moment until reaching the steady state. With a wide range of capillary number Ca and viscosity ratio M, we visualized the evolution of finger morphologies in different flow regimes including capillary fingering (CF), viscous fingering (VF), and crossover zone (CZ). Interestingly, we found that finger structures of CF regime remain the same after the breakthrough, whereas fingers of VF regime keep expanding until almost all the pore space is invaded and eventually reaches to steady state. Followed with experimental observations, a comparative quantification of fingering patterns was also conducted in terms of invasion velocity, phase saturation and fractal dimension. A dramatic increase of gas saturation, from 0.15 to 0.60 at the case of Log10Ca=-5.17 and Log10M=-2.78, is obtained in the VF regime when the steady state is reached, so is the fractal dimension (from 0.14 to 0.16, even higher than one of CF). The underlying mechanism of such fingering expansion in VF is further revealed from the time evolution of fingering after breakthrough. A previously unobserved fingering cycle, consisting of new finger forming, cap invading, breakthrough and finger vanishing, keeps repeating until the saturation reaches the maximum. We believe that these findings are of significance in evaluating extraction effectiveness, economic benefits and storage safety for subsurface applications.

How does phase behavior of surfactant/fluid/fluid systems affect fluid-fluid displacement in porous media?

Surfactant flooding is widely used in subsurface applications where high displacement efficiency is needed, such as nonaqueous phase liquid (NAPL) remediation and enhanced oil recovery (EOR). For surfactant/water/oil systems, the partitioning of surfactants in each phase is controlled by external factors, such as salinity. The third phase, microemulsions, which locates between water and oil, can be formed spontaneously at certain salinities. Therefore, the transfer of surfactants from water to other phases, which depends on salinity, can occur during surfactant flooding, resulting in spatially non-homogeneous surfactant concentrations. The critical parameters governing the displacement dynamics, such as contact angle and interfacial tension (IFT), can vary considerably due to spatially non-homogeneous surfactant concentrations. However, the influence of spatially non-homogeneous contact angle and IFT on the displacement in porous media has not been sufficiently explored. In this work, we visualized the surfactant flooding at different salinities in 2D micromodels. Our results suggest that the displacement patterns vary considerably with salinity. One displacement front was observed at low salinity, while displacement front separation occurred at intermediate and high salinity, forming two different displacement fronts. At intermediate and high salinity, we noticed that the downstream displacement was imbibition, while the upstream displacement was drainage. We suggest that the separation of displacement fronts was capillary-driven, arising from spatially non-homogeneous contact angle and IFT. Our study provides new insights into the effect of the phase behavior of surfactant/water/oil systems on displacement patterns.

Pore-Scale Modeling of Immiscible Displacement In Porous Media: The Effects of Dual Wettability

Summary Many naturally occurring porous media contain different types of grains with different wettabilities, therefore, understanding the effect of wettability heterogeneity on multiphase flow in porous media is important. We investigate the immiscible displacement during imbibition in a dual-wettability porous medium by direct pore-scale modeling. We propose a heterogeneous index (HI) to quantify the wettability heterogeneity. Our simulations on the capillary rise in dual-wettability tubes are compared with theoretical predictions, which verifies the numerical method. Our simulation results on the displacement in the dual-wettability porous media show that the wettability heterogeneity has a great impact on the fluid distribution, the capillary pressure curve, and the relative permeability curve. With the increase of wettability heterogeneity (HI), more capillary fingers are found during the displacement, the recovery rate of nonwetting fluid decreases, and the capillary pressure and the relative permeability of the wetting fluid decrease.

Competition of gravity and viscous forces in miscible vertical displacement in a three-dimensional porous medium

When viscosity and density contrast exist in the vertical miscible displacement in porous media between two fluids, the interplay between the viscous force and gravity determines the interface stability. Two stability criteria are derived to determine the interface stability. Hill's and Dumore's stability criteria are used to determine the interface stability of the sharp and diffused interface, respectively. In this study, we visualized the crossover between unstable displacement and stable displacement for a vertical displacement in porous media using microfocused x-ray computed tomography. The experiments were divided into four possible configurations: (1) unconditionally stable (gravitationally stable-viscously stable), (2) unconditionally unstable (gravitationally unstable-viscously unstable), (3) conditionally stable (gravitationally stable-viscously unstable), and (4) conditionally stable (gravitationally unstable, viscously stable). The structure of the displacement interface was visualized for the critical velocity ratio (V/Vc) in the range of 0.5–11.9. In the conditionally stable configurations 3 and 4, a crossover between stable and unstable displacements was observed. We found that Dumore's stability criterion is more appropriate for predicting interface stability than Hill's stability criterion. Viscous fingering occurs in configuration 3 when V/Vc is higher than Dumore's critical velocity, whereas gravity fingering occurs in configuration 4 when V/Vc is lower than Dumore's critical velocity. Similar events in two-dimensional experiments, such as tip-splitting, shielding, and coalescence, were also observed three-dimensionally. The significant changes in the mixing length and sweep efficiency signify the crossover between the stable and unstable displacements.

Direct Prediction of Fluid‐Fluid Displacement Efficiency in Ordered Porous Media Using the Pore Structure

AbstractFluid‐fluid displacement in porous media is common in many natural and engineering settings. Extensive studies investigated the transition of displacement patterns, but the direct prediction of the displacement efficiency using the pore structure is lacking. Here, we propose a method to directly predict the displacement efficiency with no need to solve the Navier‐Stokes and the Hagen‐Poiseuille equations in ordered porous media. The predictive method origins from the pore‐scale filling events, which can be divided into two directions such as the bulk flow direction and the transverse direction. The pore‐filling event (burst) dominates the fluid invasion for the bulk flow direction, and the invading phase forms a thin fingering channel. For the transverse direction, we introduce three invasion modes (compact, taper, and widen) to quantify fluid invasion. We can predict the finger width in each column, and the displacement efficiency can be predicted through the weighted average of the predicted finger width. We evaluate the predictive method using microfluidic experiments and pore‐network simulations, confirming that the predictive method can reasonably predict the displacement efficiency in ordered porous media. Our method can also be applicable for disorder porous media when the disorder is smaller than a critical value. The predictive method can directly predict fluid invasion according to pore structure, thus greatly improving the computational efficiency and is of significance in multiphase flow control.

High resolution adaptive implicit method for reactive transport in heterogeneous porous media

The Adaptive Implicit Method (AIM) reduces the computational cost related to simulations of field scale displacements in porous media. Standard AIM uses a mixed implicit/explicit time discretization that overcomes the time step size limitations of purely explicit approaches and considers single-point upwinding to approximate both the implicit and explicit numerical fluxes. Use of high-order fluxes improves accuracy but leads to increased stencil size and more complex Jacobians in the implicit regions. To reduce numerical diffusion and improve the accuracy of AIM while avoiding the larger stencils and nonlinearities introduced by an implicit treatment of high-order schemes, we introduce a scheme that in addition to blending implicit and explicit time discretizations, deliberately blends single-point upwind and a high-order flux-limited total variation diminishing approximation of the numerical fluxes. The proposed scheme does not interfere with the discretization of the implicit terms and the structure of the matrices that need to be solved is the same of standard AIM, making the scheme easy to apply in existing simulators. The details of the scheme are presented and it is applied to single-phase reactive transport problems in 1-, 2-, and 3-dimensions with simple homogeneous decay reactions, mixing-limited reactions, and the calcium carbonate system. For mixing-limited reactions, that are highly sensitive to numerical diffusion, accurate results depend on properly representing the sharp reactive fronts and a strategy to avoid an implicit treatment inside the reactive fronts is presented. The numerical results indicate significant gains in accuracy at the additional expense of slightly more involved flux computations in the explicit regions, that represent a small fraction of the total CPU cost.

A review of fluid displacement mechanisms in surfactant-based chemical enhanced oil recovery processes: Analyses of key influencing factors

Surfactant-based oil recovery processes are employed to lower the interfacial tension in immiscible displacement processes, change the wettability of rock to a more water-wet system and emulsify the oil to displace it in subsurface porous media. Furthermore, these phenomena can reduce the capillary pressure and enhance spontaneous imbibition. The key factors affecting such immiscible displacement process are temperature, salinity and pH of the fluids, surfactant concentration and adsorption. Therefore, before any surfactant flooding process is applied, extensive studies of fluid-fluid and rock-fluid interactions are needed. The use of other chemicals along with surfactants in chemical enhanced oil recovery (cEOR) processes have been widely considered to exploit the synergy of individual chemicals and complement the weakness arises from each of them during immiscible displacement of fluids in porous media. Therefore, such combinations of chemicals lead to alkaline-surfactant (AS), surfactant-polymer (SP), alkaline-surfactant-polymer (ASP), and nanoparticle-surfactant (NS) flooding processes, among others. In this review study, we categorised the role and displacement mechanisms of surfactants and discussed the key factors to be considered for analysing the fluid displacement in porous media.

Non-monotonic wettability effects on displacement in heterogeneous porous media

We report non-monotonic wettability effects on displacement efficiency in heterogeneous porous structures at the post-breakthrough stage, in contrast to the monotonic ones in homogeneous porous structures. Experiments on designed microfluidic chips show that there exists a critical wettability to attain the highest efficiency of displacement in the porous matrix structure combined with a preferential flow pathway, while a stronger wettability of the displacing fluid leads to a higher displacement efficiency on the same matrix structure only. The porous structure with or without a preferential flow pathway results in totally different topological characteristics of phase distribution during displacement. Pore-scale mechanisms are identified to elucidate the formation of this non-monotonic wettability rule: cooperative pore filling under weakly water-wet conditions yields the best displacement; corner flow under strongly water-wet conditions and Haines events under strongly oil-wet conditions decrease the displacement efficiency. The pore-scale findings may provide unique insights into the joint effects of both wettability and flow heterogeneity on fluid displacement in porous media.

Role of heterogeneous surface wettability on dynamic immiscible displacement, capillary pressure, and relative permeability in a CO2-water-rock system

Surface wettability is one of the major factors that regulate immiscible fluid displacement in porous media. However, the role of pore-scale wettability heterogeneity on dynamic immiscible displacement is rarely investigated. This study investigated the impact of pore-scale wettability heterogeneity on immiscible two-fluid displacement and the resulting macroscopic constitutive relations, including the capillary pressure-water saturation (Pc-Sw) and relative permeability curves. A digital Bentheimer sandstone model was obtained from X-ray micro-computed tomography (micro-CT) scanning and the rock surface wettability fields were generated based on in-situ measurements of contact angles. A graphics processing unit-accelerated lattice Boltzmann model was employed to simulate the immiscible displacement processes through the primary drainage, imbibition, and second drainage stages in a CO2-water-rock system. We found that pore-scale surface wettability heterogeneity caused noticeable local supercritical CO2 (scCO2) and water redistribution under less water-wet conditions. At the continuum scale, the Pc-Sw curves under the heterogeneous wetting condition were overall similar to those under the homogeneous wetting condition. This is because the impact of local wettability heterogeneity on the large-scale Pc-Sw curve was statistically averaged out at the entire-sample scale. The only difference was that heterogeneous wettability led to a negative entry pressure at the primary drainage stage under the intermediate-wet condition, which was caused by local, scCO2-wet surfaces. The impact of pore-scale wettability heterogeneity was more noticeable on the relative permeability curves. Particularly, the variation of the scCO2 relative permeability curve in the heterogeneous wettability scenario was more significant than that in the homogenous wettability scenario. This suggests that pore-scale wettability heterogeneity enhances the coalescence and snap-off behaviors of scCO2 blobs. This is the first study that systematically investigated the role of pore-scale wettability heterogeneity on dynamic immiscible displacement and associated Pc-Sw curves in complicated, three-dimensional porous media.