Nonwetting Phase Research Articles

Controlling parameters of co-current and counter-current imbibition in naturally fractured reservoirs

Naturally fractured formations are complex petroleum reservoirs that are poor candidates for waterflooding due to difficulties in controlling sweep. Injected water can readily propagate through the fracture system, bypassing the hydrocarbon stored in the matrix. Instead, such systems rely on spontaneous imbibition (SI) from the matrix into the extensive fracture gathering system. SI is a crucial recovery mechanism that relies on capillary pressure-dominated fluid movement. SI can occur through two modes, co-current (COSI) and counter-current (COUSI), depending on the relative direction of fluid movement in response to prevailing boundary conditions. Analytical solutions that incorporate the diffusivity coefficient, which combines relative permeability and capillary pressure curves, are used to describe co-current and counter-current imbibition mechanisms. The perturbation method is one approach in solving these analytical equations. In-situ water saturation profiles, ascertained through experimental CT scanning, serve as validation benchmarks for both co-current and counter-current models. The understanding of the SI process can give more details about the fracture-matrix interactions and the exchange function. Sensitivity studies with respect to the parameterization of the driving force for imbibition, capillary pressure, and the resistive forces, captured in relative permeability curves, can guide experimental study planning and aid in inverse problem analysis in the characterization of naturally fractured reservoirs. The results of a parametric study show that capillary pressure curve parameters, such as capillary entry pressure and capillary exponent, significantly affect the position of the waterfront which indicates the imbibition rate. In addition, the water relative permeability exponent has greater impact on both shape and position of water profile than other relative permeability parameters. The nonwetting phase parameters, like oil endpoint relative permeability and oil exponent, have the least influence on water saturation profile.

Assessment of wetting conditions in quasistatic drainage modeling using a pore morphology method and J-function wettability estimator

This study hypothesizes that a pore morphology method (PMM) can be used to accurately determine representative contact angles by effectively capturing fluid morphologies within porous media, thereby overcoming the challenges of accurate wettability characterization for porous materials. We introduce a methodology for the estimation of the wettability, along with measurements of capillary pressure and relative permeability, using a PMM. This approach employs morphological operations to model quasistatic drainage under different surface wetting conditions. To assess PMM, fluid morphologies resulting from the simulation were compared with experimentally derived geometric and thermodynamic contact angles, along with surface area, and Euler characteristic measurements. Based on fluid configurations under different wettability conditions, we find that PMM effectively captures realistic fluid morphologies. At lower capillary pressures, PMM exhibits superior adaptability to a wide range of wetting behaviors. However, at higher capillary pressures, PMM does not reflect the true morphologies of the fluid due to the interfaces that exist in the pendular state. The influence of these effects at higher capillary pressures introduces an inaccuracy in the simulated relative permeability of the wetting phase, though they do not affect the relative permeability of the nonwetting phase. Overall, these findings can significantly enhance the accuracy of wettability characterization in porous media, thereby advancing our understanding and prediction of fluid behavior in surface-based research of porous materials.

Evaluation of CO2/Water Imbibition Relative Permeability Curves in Sandstone Core Flooding—A CFD Study

Greenhouse gases such as CO2 can be safely captured and stored in geologic formations, which in turn can reduce the carbon imprint in the Earth’s atmosphere and therefore help toward reducing global warming. The relative permeability characteristics in CO2/brine or CO2/water systems provide insight into the CO2 trapping efficacy of formations such as sandstone rocks. In this research, CO2/water imbibition relative permeability characteristics in a typical sandstone core sample are numerically evaluated. This work uses transient computational fluid dynamics (CFD) simulations to study relative permeability characteristics, and a sensitivity analysis is performed based on two different injection pressures and absolute permeability values of the sandstone rock material. Results show that when the irreducible water fraction remains unchanged, the imbibition relative permeability to the non-wetting phase decreases with an increase in injection pressure within the sandstone core sample. Also, with the irreducible water fraction being unchanged, relative permeabilities to both non-wetting and wetting phases decrease with an increase in the absolute permeability of the rock material. Finally, at irreducible water saturation, relative permeability to the gas phase decreases with an increase in injection pressure.

Two-Phase Incompressible Flow with Dynamic Capillary Pressure in a Heterogeneous Porous Media

We prove the existence of weak solutions of a two-incompressible immiscible wetting and non-wetting fluids phase flow model in porous media with dynamic capillary pressure. This model is a coupled system which includes a nonlinear parabolic saturation equation and an elliptic pressure–velocity equation. In the regularized case, the existence and uniqueness of the weak solution are obtained. We let the regularization parameter be η→0 to prove the existence of weak solutions.

Nanoparticle transport in partially saturated porous media: Attachment at fluid interfaces

Like the solid-water interface (SWI), air-water and oil-water interfaces (AWI and OWI) also act as collectors for nano-sized particles in porous media. The attachment of hydrophobic nanoparticles, which is often favorable and irreversible, is of particular interest because the transport and retention of such particles is closely linked to the fate of nanoplastics in unsaturated subsurface environments and the success of nanoremediation practices. Here, we show how a pore-network model (PNM) can be used to upscale the kinetics and extent of irreversible nanoparticle attachment at a single fluid-fluid interface under conditions of advection and dispersion in a sphere packing. By focusing on a trapped (immobile) non-wetting phase, we highlight a fundamental difference between the single-collector contact efficiency of AWI/OWI and SWI. Namely, AWI/OWI collectors, which are largely by-passed by the flowing aqueous phase, are exposed to a hydrodynamic environment dominated by diffusion. This difference has profound implications for the modelling of nanoparticle transport in porous media at the continuum (Darcy) scale. This study reveals the potential of pore network modelling as an essential complement to continuum models for upscaling the behavior of nanocolloids in porous media.

Factors influencing residual air saturation during consecutive imbibition processes in an air-water two-phase fine sandy medium – A laboratory-scale experimental study

The residual air saturation plays a crucial role in modeling hydrological processes of groundwater and the migration and distribution of contaminants in subsurface environments. However, the influence of factors such as media properties, displacement history, and hydrodynamic conditions on the residual air saturation is not consistent across different displacement scenarios. We conducted consecutive drainage-imbibition cycles in sand-packed columns under hydraulic conditions resembling natural subsurface environments, to investigate the impact of wetting flow rate, initial fluid state, and number of imbibition rounds (NIR) on residual air saturation. The results indicate that residual air saturation changes throughout the imbibition process, with variations separated into three distinct stages, namely, unstable residual air saturation (Sgr-u), momentary residual air saturation (Sgr-m), and stable residual air saturation (Sgr). The results also suggest that the transition from Sgr-u to Sgr is driven by changes in hydraulic pressure and gradient; the calculated values followed the following trend: Sgr > Sgr-u > Sgr-m. An increase in capillary number, which ranged from 1.46 × 10−7 to 3.07 × 10−6, increased Sgr-u and Sgr-m in some columns. The increase in Sgr ranged from 0.034 to 0.117 across all the experimental columns; this consistent increase can be explained by water film expansion at the primary wetting front along with a strengthening of the hydraulic gradient during water injection. Both the pre-covered water film on the sand grain surface and a pore-to-throat aspect ratio of up to 4.42 were identified as important factors for the increased residual air saturation observed during the imbibition process. Initial air saturation (Sai) positively influenced all three types of residual air saturation, while initial capillary pressure (Pci) exhibited a more pronounced inhibitory effect on residual air saturation, as it can partly characterized the initial connectivity of the air phase generated under different drying flow rates. Under identical wetting flow rate conditions, Sgr was higher during the second imbibition than during the first imbibition due to variations in initial fluid state, involving both fluid distribution and the concentration of dissolved air in the pore water. In contrast, NIR did not have an obvious effect on the three types of residual air saturation. This work aims to provide empirical evidences and offer further insights into the capture of non-wetting phases in groundwater environments, as well as to put forward some potential suggestion for future investigations on the retention and migration of contaminants that involves multiphase interface interactions in subsurface environments.

Influence of Local Aperture Heterogeneity on Invading Fluid Connectivity During Rough Fracture Drainage

Determining the (in)efficiency of wetting phase displacement by an invading non-wetting phase (drainage) in a single fracture is key to modelling upscaled properties such as relative permeability and capillary pressure. These constitutive relationships are fundamental to quantifying the contribution, or lack thereof, of conductive fracture systems to long-term leakage rates. Single-fracture-scale modelling and experimental studies have investigated this process, however, a lack of visualization of drainage in a truly representative sample at sufficient spatial and temporal resolution limits their predictive insights. Here, we used fast synchrotron X-ray tomography to image drainage in a natural geological fracture by capturing consecutive 2.75 μm voxel images with a 1 s scan time. Drainage was conducted under capillary-dominated conditions, where percolation-type patterns are expected. We observe this continuously connected invasion (capillary fingering) only to be valid in local regions with relative roughness, λb ≤ 0.56. Fractal dimension analysis of these invasion patterns strongly aligns with capillary fingering patterns previously reported in low λb fractures and porous media. Connected invasion is prevented from being the dominant invasion mechanism globally due to high aperture heterogeneity, where we observe disconnected invasion (snap-off, fragmented clusters) to be pervasive in local regions where λb ≥ 0.67. Our results indicate that relative roughness has significant control on flow as it influences fluid conductivity and thus provides an important metric to predict invasion dynamics during slow drainage.

A two-phase flow model simulating water penetration into pharmaceutical tablets

The purpose of the study is introduce a two-phase flow model to simulate water penetration into pharmaceutical tablets. This model was built by integrating Darcy’s law with the continuity principle, on the premise that water penetration was driven by capillary actions. Notably, this model concerned both the ingress of water (wetting phase) and simultaneous displacement of air (non-wetting phase). Due to the interference of the two fluids, the relative permeability and capillary pressure vary during water penetration. Evolution of these parameters was incorporated in the model. Calibration of the model by water penetration experiments of the microcrystalline cellulose (MCC) tablet yielded an average pore radius of 42 nm. This derived result was corroborated by FIB-SEM analysis revealing the presence of extensive microporosity within MCC particles with an average radius of ∼30 nm. Further validation was achieved through close resemblance between the simulated and experimental water penetration profiles of MCC tablets possessing different porosities. Overall, this study underscored the advantage of the two-phase flow model over single-phase flow models, by capturing the dependence of permeability and capillary pressure on water saturation. Therefore it holds promise for an enhanced description of water penetration into tablets.

Pore-scale simulation of H2-brine system relevant for underground hydrogen storage: A lattice Boltzmann investigation

Underground hydrogen (H2) storage in saline aquifers is a viable solution for large-scale H2 storage. Due to its remarkably low viscosity and density, the flow of H2 within saline aquifers exhibits strong instability, which needs to be thoroughly investigated to ensure safe operations at the storage site. For the first time, we develop a lattice Boltzmann model tailored for pore-scale simulations of the H2-brine system under typical subsurface storage conditions. The model captures the significant contrast of fluid properties between H2 and brine, and it offers the flexibility to adjust the contact angle to suit varying wetting conditions. We show that the snap-off is enhanced in a system with a high capillary number and a small contact angle. These conditions lead to a low recovery factor, which is unfavorable for H2 production from the aquifer. Moreover, the relative permeability curves, computed from the simulation results, exhibit distinct behaviors for H2 and brine. In the case of the wetting phase, the relative permeability can be quantified using the quadratic expression, whereas for the non-wetting phase, the relative permeability exhibits a nearly linear behavior, and saturation alone appears insufficient to characterize the relative permeability at large saturations of non-wetting phase. This implies that different formula for liquid and gas phases may be employed for continuum-scale simulations.

Influence of binder content on gas-water two-phase flow and displacement phase diagram in the gas diffusion layer of PEMFC: A pore network view

Understanding the gas-water flow dynamics in the gas diffusion layer (GDL) is one of the keys to improving the proton exchange membrane fuel cell's (PEMFC) overall performance and avoiding water flooding. Yet, the relationship between the two-phase flow and micro-scale GDL structures (including binder, PTFE, and fiber skeleton) is not well understood. In this study, three-dimensional GDL structures with different fractions of binder contents (φb=0%∼50%) and a fixed porosity of 75.6 % are confidently reconstructed based on high-resolution images from the confocal microscope, implying that the addition of binder will increase the number of large pores and cause a bimodal throat size distribution through morphology analysis. Thereafter, drainage simulations are performed under a wide range of capillary number (−9 < log Ca <0) and viscosity ratio (−3 < log M < 2) by the pore network model (PNM), which robustly predicts the displacement phase diagram of viscous fingering, capillary fingering, stable displacement, and transitional regime. In the viscous fingering and stable displacement regime, the nonwetting phase saturation (Snw) is nearly the same for different φb, implying the fluid invading pathway does not change much with the addition of binder. However, in the capillary fingering regime (refer to the actual operating conditions), Snw increases rapidly with φbat the breakthrough time and its transient value continues to increase until the steady state, which may be attributed to the increased fractions of pores above the capillary threshold attributed by the bimodal throat size distribution. In addition, the effective water permeability increases sharply with φb, whereas the gas permeability remains almost constant, which means such pore structure alteration by adding the binder is beneficial to water disposal in PEMFC. This research provides insights into delineating the effect of pore and throat size distribution alteration by adding binder on two-phase dynamics in GDL.

Investigating snap-off behavior during spontaneous imbibition in 3D pore-throat model by pseudopotential lattice Boltzmann method

As a result of complex pore-throat geometry and precursor corner flow, the snap-off of the non-wetting phase occurs during the spontaneous imbibition (SI) of wetting phase. However, accurate modeling of such pore-scale flow behavior remains a big challenge, and its influencing factors remain unclear. In this study, an improved pseudopotential lattice Boltzmann method (LBM) is used to analyze the snap-off behavior during the SI process in three-dimensional (3D) pore-throat models with rough surfaces. The influence of the pore-to-throat size ratio (λ), contact angles (θ), and Ohnesorge number (Oh) on the occurrence of the snap-off are investigated and based on which a 3D phase diagram is established. The snap-off is more likely to occur with the increase in λ and Oh and decrease in θ, respectively. Only when the λ is ≥2 and the θ is <13°, the snap-off may occur. With the increase in θ from 0° to 13°, the snap-off is suppressed due to the relatively small advancing difference between the corner flow and the bulk meniscus. Volume fraction of the entrapped gas bubble in the pore increases with the increase in λ and Oh and the decrease in θ. The time when snap-off occurred increases with the increase in λ and θ, and decrease in Oh. These results are fundamental for investigating snap-off phenomena in real 3D pore space and guide how to avoid or facilitate the occurrence of snap-off and to control the degree of snap-off.

Steady-state two-phase relative permeability measurements in proppant-packed rough-walled fractures

Understanding multiphase flow in fractures filled with minerals and proppants is vital in various subsurface applications. Limited experimental data have led to reliance on correlations lacking physical basis. We conducted experiments to characterize relative permeability in rough-walled fractures packed with unconsolidated porous media. We tested fractures packed with water-wet 40/70 sand (silica) and surface-coated ceramic proppants. Brine and mineral oil were used as the wetting and non-wetting fluid phases, respectively. Steady-state (SS) drainage (non-wetting-phase displacing wetting-phase) and imbibition (wetting-phase displacing non-wetting-phase) tests were performed under a wide range of saturation histories (full-cycle and scanning-curves) to study relative permeability hysteresis of the propped fractures. Every SS drainage or imbibition test consisted of several discrete points at which fluid saturations and the corresponding relative permeability were measured by varying the fractional flow rates of fluids whilst maintaining a constant total flow rate. We analyzed residual non-wetting phase saturations and relative permeability trends to understand two-phase flow behavior in each proppant pack. High-resolution x-ray microtomography was used to understand the pore-scale topology, wettability, and to provide insights about the pore-scale displacement mechanisms involved in this study. The results showed that commonly used models to estimate relative permeabilities of fractures significantly overestimated the SS brine and oil relative permeabilities (denoted as krw and kro) measured in this study. Further analysis unveiled that the kro values during imbibition exceeded their drainage counterparts in both proppants, the ceramic proppant exhibited a lower initial water saturation and a higher end-point kro permeability at the end of the drainage displacement, as well as higher krw across all flooding processes. Updated fitting parameters for a Brooks-Corey-type relative permeability correlation are introduced. This study presents improved insights, extensive experimentally generated relative permeability data, and an updated relative permeability correlation, which can be collectively utilized to reduce uncertainties associated with continuum-scale forecasts of multiphase flow behavior in fractured subsurface formations.

Comparison of Newtonian and glycerol-water solution-based SiO2 nanofluid droplets impacting on heated spherical surfaces

The dynamic interactions of liquid droplets with heated spherical particles, relevant across various scientific and engineering disciplines, display intriguing collision behaviors whose principles are yet to be fully deciphered. This investigation utilizes high-speed photography to explore the wetting and non-wetting responses of different Newtonian and glycerol-water solution-based SiO2 nanofluid droplets upon contact with heated particles. Findings indicate that nanofluid droplets disrupt the thermal field and modify the surface morphology of particles more extensively under wetting than non-wetting conditions. Wetting conditions lead to significant alterations in the liquid film thickness and notable velocity field disruptions for droplets of deionized water and glycerol solution. Conversely, in the non-wetting phase, droplets nearing full rebound cause less disturbance to the velocity field, a behavior consistent across all fluid types and particle temperatures. The shape changes nanofluid droplets undergo when rebounding and separating from the particle surface are similar to those seen in glycerol solution and water droplets. Droplets in the breakup-rebound phase experience shorter contact times than those merely rebounding. A phase diagram is presented, detailing wetting (receding-deposition and boiling-breakup) and non-wetting (rebound and breakup-rebound) actions. An increase in the Weber number necessitates a higher particle temperature for the transition from rebound to breakup-rebound, which corroborates with theoretical insights. Furthermore, droplets achieve their maximum spreading area during the boiling-breakup mode.

Quantitative characterization of imbibition in fractured porous media based on fractal theory

In low-permeability reservoirs, such as shale and tight sandstone, imbibition is an important mechanism for enhancing oil recovery. After hydraulic fracturing treatment, these reservoirs create a network of fracture pathways for fluid flow. Therefore, understanding the imbibition mechanisms in fractured porous media and quantitatively characterizing oil–water distribution are crucial for the development of low-permeability reservoirs. In this study, a mathematical model of two-phase flow in porous media with branching fractures was established. The phase-field method was employed to track the oil–water interface, and quantitative characterization of imbibition was conducted based on fractal theory, and the effects of wetting phase injection rate, the number of disconnected fractures, fracture spacing, and fracture morphology on imbibition in branched fracture porous media were discussed. The research findings indicate that in branched fracture porous media, both co-current and countercurrent imbibition processes occur simultaneously, and there exists a diffusion interface layer with a certain thickness at the oil–water interface. The hydraulic pressure generated by the wetting phase injection rate provides the driving force for imbibition oil recovery, but it also affects the contact time between the wetting and non-wetting phases. The presence of disconnected fractures hinders the propagation of hydraulic pressure, reducing the effectiveness of imbibition. The imbibition displacement zone is limited and occurs only within a certain range near the fractures. As the number of branching fractures increases, the channels for the wetting phase to enter matrix pores are enhanced, resulting in higher efficiency of imbibition displacement of the oil phase. The results of this research can provide guidance for the design of fracturing programs and recovery prediction in low-permeability reservoirs.

Complexity upgrade and triggering mechanism of mixed-wettability: Comparative study of CO2 displacement in different phases

Complex pore structures and wettability affect CO2 storage in underground reservoirs. Revealing the flow law of CO2 in complex reservoirs is crucial for evaluating storage stability and security. Considering the complexity of the pore structure and wettability of rock, a complex mixed-wettability characterization method based on a complex pore structure is proposed. Matrix numerical models for two-dimensional heterogeneous complex mixed-wettability rock were developed to simulate CO2 displacement in different phases. A comparative study found that, under single-phase wettability, the weaker the wettability, the better the effect of gaseous CO2 displacement. Moreover, the stronger the wettability, the better the displacement effect of ScCO2. The wetting phase of CO2 was transformed from the non-wetting phase. At the late stage of gaseous CO2 displacement, when the contact angles were 30° and 60°, the displaced water phase was absorbed back into the matrix owing to imbibition, resulting in the formation of a peak in the displacement efficiency curve. Compared to that at a contact angle of 60°, the displacement efficiency at a contact angle of 30° decreased more significantly after the peaks, while the suck-back phenomenon did not occur when the contact angle was 90°. Under mixed-wettability conditions, the flow law of CO2 in different phases is directly affected by the contact angle of the pore walls. The displacement efficiencies of gaseous CO2 and ScCO2 increased by 9.58% and 17.96%, respectively, owing to the dual driving force caused by imbibition. The complexity of mixed-wettability is upgraded by providing pore walls with different proportions of contact angles (six types). The flow law of different phases of CO2 showed that, the higher the proportion of walls with small contact angles (3:2:1), the worse the displacement effect of gaseous CO2 and the better the displacement effect of ScCO2. Compared with single-phase wettability and mixed-wettability, the displacement efficiency of gaseous CO2 and ScCO2 under complex mixed-wettability decreased by 4.26%, 1.00% and 20.41%, 3.37%, respectively. Therefore, ignoring complex mixed-wettability often leads to a higher displacement efficiency.

Behaviors of non-wetting phase snap-off events in two-phase flow: microscopic phenomena and macroscopic effects

Behaviors of non-wetting phase snap-off events in two-phase flow: microscopic phenomena and macroscopic effects

Bridging the gap: Connecting pore-scale and continuum-scale simulations for immiscible multiphase flow in porous media

This study aims to bridge length scales in immiscible multiphase flow simulation by connecting two published governing equations at the pore-scale and continuum-scale through a novel validation framework. We employ Niessner and Hassnaizadeh's [“A model for two-phase flow in porous media including fluid-fluid interfacial area,” Water Resour. Res. 44(8), W08439 (2008)] continuum-scale model for multiphase flow in porous media, combined with the geometric equation of state of McClure et al. [“Modeling geometric state for fluids in porous media: Evolution of the Euler characteristic,” Transp. Porous Med. 133(2), 229–250 (2020)]. Pore-scale fluid configurations simulated with the lattice-Boltzmann method are used to validate the continuum-scale results. We propose a mapping from the continuum-scale to pore-scale utilizing a generalized additive model to predict non-wetting phase Euler characteristics during imbibition, effectively bridging the continuum-to-pore length scale gap. Continuum-scale simulated measures of specific interfacial area, saturation, and capillary pressure are directly compared to up-scaled pore-scale simulation results. This research develops a numerical framework capable of capturing multiscale flow equations establishing a connection between pore-scale and continuum-scale simulations.

Micro computed tomography images of capillary actions in rough and irregular granular materials

The present work investigates the effect of both surface roughness and particle morphology on the retention behaviour of granular materials via X-ray micro-computed tomography (µCT) observations. X-ray µCT images were taken on two types of spherical glass beads (i.e. smooth and rough) and two different sands (i.e. natural and roughened). Each sample was subjected to drainage and soaking paths consisting in a multiphase ‘static’ flow of potassium iodine (KI) brine (wetting phase) and dry air (non-wetting phase). Tomograms were obtained at different saturation states ranging from fully brine saturated to air dry conditions with 6.2 μm voxel size resolution. The data acquisition and pre-processing are here described while all data, a total of 48 tomograms, are made publicly available. The combined dataset offers new opportunities to study the influence of surface roughness and particle morphology on capillary actions as well as supporting validation of pore-scale models of multiphase flow in granular materials.

Steady-State Dynamics of Ganglia Populations During Immiscible Two-Phase Flows in Porous Micromodels: Effects of the Capillary Number and Flow Ratio on Effective Rheology and Size Distributions

We study experimentally the flow of non-wetting ganglia during the co-injection of n-heptane and water in a predominantly 2D PMMA micromodel, which is constructed based on a stochastic digital algorithm. The dynamics of the phase distribution patterns are recorded optically and post-processed using cluster identification and motion tracking algorithms in order to study the characteristics and the interactions between the mobile and stranded ganglia populations. We focus primarily on the effects of the capillary number (Ca) and the ratio of the injection flow rates (Q) on the observed ganglia size distributions and the effective two-phase rheology. Our experimental setup allows for the study of ganglia fragmentation and coalescence dynamics over five orders of magnitude (in terms ganglia sizes), thus offering novel physical insight on the pore-scale characteristics of different ganglia populations and on how their interactions determine the relative permeability of the non-wetting phase. We demonstrate that the rates of ganglia fragmentation and coalescence intensify at higher Ca values, as viscous forces become dominant over capillary ones, leading to a log-normal size distribution that shifts toward smaller mean values. This effect is directly correlated with the emergence of new flow paths that develop progressively through narrower pores-throats, where the continuous wetting phase sweeps ganglia with sizes smaller than the mean pore-throat diameter. These flow paths further contribute to the Darcy scale velocity of the non-wetting phase, thus leading to a power-law Darcian regime at intermediate Ca values with a scaling exponent that is found to be a function of Q.

A CRITICAL ANALYSIS OF CRUDE OIL FLOW THROUGH POROUS ENVIRONMENTS IN TERTIARY MIGRATION

In the process of tertiary migration of crude oil, the phase that occurs after the cessation of primary exploitation of petroleum fluid deposits, the deposit is characterized by a state of maximum discontinuity of microscale phases and their abnormal gravitational positioning. This is precisely why it is necessary to discuss the blocking/unblocking mechanisms of wetting phase and non-wetting phase plugs in/out of capillary microtraps. The article presents for the first time a microfluidic behavior of crude oil through cores, with the analysis of polymer flow through rock pores and their filling with petroleum fluids.