Fundamental Study of Pore Morphology Effect in Low Tension Polymer Flooding or Polymer–Assisted Dilute Surfactant Flooding

Low Tension Polymer Flooding or Polymer Assisted Dilute Surfactant Flooding is generally deployed as a method to produce additional oil trapped in oil reservoirs after waterflooding. Fundamental study of microscopic mechanisms and pore-level phenomena in Polymer Assisted Dilute Surfactant Flooding needs more investigation. Of particular concern and interest is to probe into and document the effect of pore morphology and structure on microscopic phenomena occurring at pore level. No previous works on the effect of pore morphology in Polymer Assisted Dilute Surfactant Flooding has been reported in the literature. In this study, one-quarter five-spot glass micromodels were deployed to examine the effect of porous media morphology and structure on microscopic mechanisms as well as macroscopic behavior of Polymer Assisted Dilute Surfactant Flooding. Four types of pore morphologies were employed to study this factor. Results show that the pore geometric properties in a porous medium will dictate the degree of displacement front instability, capillary imbalance, viscous fingering, wetting characteristics and its distribution, and finally magnitude of ultimate oil recovery. We also found that the formation of flow scheme is dramatically influenced by the pre-designed injection scheme.     

Mechanical study of the effect of fractional-wettability on multiphase fluid flow

Fractional wettability has been widely recognized in most of the oil reservoirs and it is a crucial factor that controls the fluid flow behavior in porous medium. The overall effect of the proportion of oil-wet grains on the fluid flow properties has been well discussed. However, recent studies found that the random distribution and coordination of oil-wet and water-wet grains could make multi-phase flow behaviors extremely complicated in such media. The multiphase flow mechanisms in fractional wettability media remains unclear. In this study, oil imbibition experiments were systematically conducted using glass cylinders packed with fractional-wet glass beads. To study the effect of fractional wettability on multiple-phase flow properties, samples with different oil-wet grain proportions were prepared, and fifteen repeated experiments were conducted for each oil-wet proportion. The experimental results showed that oil imbibition was largely dependent on but not strictly a function of the proportion of oil-wet grains in the medium. The imbibition behaviors of samples with the same fractional proportion could vary significantly, as some samples exhibited complete oil migration, while others did not. This probabilistic phenomenon is likely due to the random distribution of oil-wet and water-wet grains. A pore throat may behave as oil-wet or water-wet depending on the relative proportion of oil-wet grains the pore throat contains. When the grains that comprise the pore throat are dominated by oil-wet grains, the throat behaves as oil-wet, and vice versa. Only when these oil-wet pore throats are connected to form a complete oil-wet pathway throughout the medium can the oil continuously imbibe into the medium. Therefore, the extent of oil imbibition depends on the completeness of the oil-wet pathway, which is controlled by the proportion of oil-wet grains in the medium. The higher the proportion of oil-wet grains in the medium, the larger the number of oil-wet pore throats that can form; thus, the higher the possibility that those oil-wet pore throats can connect to form continuous oil-wet pathways.     

Microscopic Mechanisms of Oil Recovery By Near-Miscible Gas Injection

As gas flooding becomes a more viable means of enhanced oil recovery, it is important to identify and understand the pore-scale flow mechanisms, both for the development of improved gas flooding applications and for the predicting phase mobilisation under secondary and tertiary gas flooding. The purpose of this study was to visually investigate the pore-level mechanisms of oil recovery by near-miscible secondary and tertiary gas floods. High-pressure glass micromodels and model fluids representing a near-miscible fluid system were used for the flow experiments. A new pore-scale recovery mechanism was identified which significantly contributed to oil recovery through enhanced flow and cross-flow between the bypassed pores and the injected gas. This mechanism is strongly related to a very low gas/oil interfacial tension (IFT), perfect wetting conditions and simultaneous flow of gas and oil in the same pore, all of which occur as the gas/oil critical point is approached. The results of this study helps us to better understand the pore-scale mechanisms of oil recovery in very low-IFT (near-miscible) systems. In particular we show that in near-miscible gas floods, behind the main gas front, the recovery of the oil continues by cross-flow from the bypassed pores into the main flow stream and as a result almost all of the oil, which has been contacted by the gas, could be recovered. Our observations in high-pressure micromodel experiments have demonstrated that this mechanism can only occur in near-miscible processes (as opposed to immiscible and completely miscible processes), which makes oil displacement by near-miscible gas floods a very effective process.     

Microscale Visual Study of End Effects at Permeability Discontinuities

The physical effect of multiphase fluid distribution and flow at permeability boundaries has not been fully investigated, particularly at the pore scale (1–100 μm), although such behaviour can significantly affect the overall scaled-up reservoir trapping capacity and production performance. In this article, microscale physical models have been used to qualitatively study the pore scale flow events at permeability boundaries, both high to low and vice versa, to gain a better understanding of the role of these boundaries and water saturation on multiphase displacement behaviour at the pore scale. We have used etched glass models of stripes of large and small (a factor of two) pores with circular matrix. Capillary pressure, which is the controlling parameter is itself dependant on pore size and its spatial distribution, the magnitude of the interfacial tensions and the wettability between the fluids and the solid surface of the models. Sometimes, the only way the non-wetting fluid can penetrate the boundary is through a fortuitous leakage, whereby the presence of an initial saturation reduces the controlling capillary pressure. Examples are demonstrated including mechanisms of end-effects and how capillary boundary resistance (due to capillary forces) can be broken down and fluid movement across the boundary can develop. These micromodel experiments show vividly that connate water can assist in these processes, particularly oil trapping and leakage of water across a permeability boundary.     

Analysis of capillary interaction and oil recovery under ultrasonic waves

Although, the effects of ultrasonic irradiation on multiphase flow through porous media have been studied in the past few decades, the physics of the acoustic interaction between fluid and rock is not yet well understood. Various mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to Bjerknes forces, oscillation and excitation of capillary trapped oil drops, forces generated by cavitating bubbles, and sonocapillary effects. Insight into the physical principles governing the mobilization of oil by ultrasonic waves is vital for developing and implementing novel techniques of oil extraction. This paper aims at identifying and analyzing the influence of high-frequency, high-intensity ultrasonic radiation on capillary imbibition. Laboratory experiments were performed using cylindrical Berea sandstone and Indiana limestone samples with all sides (quasi-co-current imbibition), and only one side (counter-current imbibition) contacting with the aqueous phase. The oil saturated cores were placed in an ultrasonic bath, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time. Air–water, mineral oil–brine, mineral oil–surfactant solution and mineral oil-polymer solution experiments were run each exploring a separate physical process governing acoustic stimulation. Water–air imbibition tests isolate the effect of ultrasound on wettability, capillarity and density, while oil–brine imbibition experiments help outline the ultrasonic effect on viscosity and interfacial interaction between oil, rock and aqueous phase. We find that ultrasonic irradiation enhances capillary imbibition recovery of oil for various fluid pairs, and that such process is dependent on the interfacial tension and density of the fluids. Although more evidence is needed, some runs hint that wettability was not altered substantially under ultrasound. Preliminary analysis of the imbibition recoveries also suggests that ultrasound enhances surfactant solubility and reduce surfactant adsorption onto the rock matrix. Additionally, counter-current experiments involving kerosene and brine in epoxy coated Berea sandstone showed a dramatic decline in recovery. Therefore, the effectiveness of any ultrasonic application may strongly depend on the nature of interaction type, i.e., co- or counter-current flow. A modified form of an exponential model was employed to fit the recovery curves in an attempt to quantify the factors causing the incremental recovery by ultrasonic waves for different fluid pairs and rock types.     

Micromodel Observation of the Role of Oil Layers in Three-Phase Flow

We have studied the flow of a non-aqueous phase liquid (NAPL, or oil), water and air at the pore scale using a micromodel. The pore space pattern from a photomicrograph of a two-dimensional section through a Berea sandstone was etched onto a silicon wafer. The sizes of the pores in the micromodel are in the range 3–30,m and are the same as observed in the rock from which the image was taken. We conducted three-phase displacement experiments at low capillary numbers (in the order of 10^-7) to observe the presence of predicted displacement mechanisms at the pore scale. We observed stable oil layers between the wetting phase (water) and the non-wetting phase (gas) for the water–decane–air system, which has a negative equilibrium spreading coefficient, as well as four different types of double displacements where one fluid displaces another that displaces a third. Double imbibition and double drainage are readily observed, but the existence of an oil layer surrounding the gas phase makes the other double displacement combinations very unlikely.     

Characterizing the Role of Shale Geometry and Connate Water Saturation on Performance of Polymer Flooding in Heavy Oil Reservoirs: Experimental Observations and Numerical Simulations

Many heavy oil reservoirs contain discontinuous shales which act as barriers or baffles to flow. However, there is a lack of fundamental understanding about how the shale geometrical characteristics affect the reservoir performance, especially during polymer flooding of heavy oils. In this study, a series of polymer injection processes have been performed on five-spot glass micromodels with different shale geometrical characteristics that are initially saturated with the heavy oil. The available geological characteristics from one of the Iranian oilfields were considered for the construction of the flow patterns by using a controlled-laser technology. Oil recoveries as a function of pore volumes of injected fluid were determined from analysis of continuously recorded images during the experiments. We observed a clear bypassing of displacing fluid which results in premature breakthrough of injected fluid due to the shale streaks. Moreover, the results showed a decrease of oil recovery when shales’ orientation, length, spacing, distance of the shale from production well, and density of shales increased. In contrast, an increase of shale discontinuity or distance of the shale streak from the injection well increased oil recovery. The obtained experimental data have also been used for developing and validating a numerical model where good matching performance has been observed between our experimental observations and simulation results. Finally, the role of connate water saturation during polymer flooding in systems containing flow barriers has been illustrated using pore level visualizations. The microscopic observations confirmed that besides the effect of shale streaks as heterogeneity in porous medium, when connate water is present, the trapped water demonstrates another source of disturbance and causes additional perturbations to the displacement interface leading to more irregular fingering patterns especially behind the shale streaks and also causes a reduction of ultimate oil recovery. This study reveals the application of glass micromodel experiments for studying the effects of barriers on oil recovery and flow patterns during EOR processes and also may provide a set of benchmark data for recovery of oil by immiscible polymer flood around discontinuous shales.     

Effect of Wetting on Gravity Drainage in Porous Media

A series of benchmark experiments on the effect of the wetting state on the flow properties in porous media were performed, allowing us to relate the wetting properties at the pore scale to the macroscale hydrodynamics. Drainage of n-alkanes (oils) displaced by air in a model porous medium consisting of water-wet sand was studied using gamma-ray densitometry and weight measurements. The enormous advantage of our system is that we know and control the wetting properties perfectly: we can tune the wetting properties by changing the salinity of the water. This allows us to perform porous medium flow experiments for the different wetting states without changing the transport properties (viscosity and density) of the oil. Drainage is found to be more efficient, and consequently oil recovery more important for partial wetting.     

页岩有机质纳米孔隙气体吸附与流动规律研究

页岩储层孔隙结构复杂, 气体赋存方式多样. 有机质孔隙形状对受限空间气体吸附和流动规律的影响尚不明确, 导致难以准确认识页岩气藏气体渗流机理. 为解决该问题, 本文首先采用巨正则蒙特卡洛方法模拟气体在不同形状有机质孔隙(圆形孔隙、狭长孔隙、三角形孔隙、方形孔隙)内吸附过程, 发现不同形状孔隙内吸附规律符合朗格缪尔单层吸附规律, 分析了绝对吸附量、过剩吸附浓量、气体吸附参数随孔隙尺寸、压力的变化, 研究了孔隙形状对气体吸附的影响. 在明确不同形状有机质孔隙内气体热力学吸附规律基础上, 建立不同形状有机质孔隙内吸附气表面扩散数学模型和考虑滑脱效应的自由气流动数学模型, 结合分子吸附模拟结果研究了不同孔隙形状、孔隙尺寸有机质孔隙内吸附气流动与自由气流动对气体渗透率的贡献. 结果表明, 狭长孔隙内最大吸附浓度和朗格缪尔压力最高, 吸附气表面扩散能力最弱. 孔隙半径5 nm以上时, 吸附气表面扩散对气体渗透率影响可忽略. 本文研究揭示了页岩气藏实际生产过程中有机质孔隙形状对页岩气吸附和流动能力的影响机制.      

Mechanisms Involved in Microbially Enhanced Oil Recovery

Microbial enhanced oil recovery (MEOR) represents a possible cost-effective tertiary oil recovery method. Although the idea of MEOR has been around for more than 75 years, even now little is known of the mechanisms involved. In this study, Draugen and Ekofisk enrichment cultures, along with Pseudomonas spp. were utilized to study the selected MEOR mechanisms. Substrates which could potentially stimulate the microorganisms were examined, and l-fructose, d-galacturonic acid, turnose, pyruvic acid and pyruvic acid methyl ester were found to be the best utilized by the Ekofisk fermentative enrichment culture. Modelling results indicated that a mechanism likely to be important for enhanced oil recovery is biofilm formation, as it required a lower in situ cell concentration compared with some of the other MEOR mechanisms. The bacterial cells themselves were found to play an important role in the formation of emulsions. Bulk coreflood and flow cell experiments were performed to examine MEOR mechanisms, and microbial growth was found to lead to possible alterations in wettability. This was observed as a change in wettability from oil wet (contact angle 154°) to water wet (0°) due to the formation of biofilms on the polycarbonate coupons.     

Analysis of Pore Pressure Distribution in Shale Formations under Hydraulic,Chemical, Thermal and Electrical Interactions

Change in pore pressure in chemically active rocks such as shale is caused by several mechanisms and numerous studies have been carried out to investigate these mechanisms. However, some important coupling terms or driving forces have been neglected in these studies due to simplifying assumptions. In this study, a hydro-chemo-thermo-electrical model based on finite element method is presented to investigate the change in pore pressure in shale formations resulted from thermal, hydraulic, chemical and electric potential gradients. The change in pore pressure is induced by hydraulic conduction, chemical, electrical and thermal osmotic flow. In order to solve the problem of ion transfer under the influence of an electrical field, the Nernst–Planck equation is used. In addition, ion advection is considered to investigate its possible effect on ion transfer for the range of shale permeability. All equations are derived based on the thermodynamics of irreversible processes in a discontinuous system. The numerical results are compared against existing and derived uncoupled analytical solutions and good agreement is observed. The numerical results showed that the ion transfer and pore pressure are considerably affected by the electric field in the vicinity of the wellbore. It was also found that advection can play a remarkable role in ion transfer in shale formations. It was further shown that the change in pore pressure in shale formation is characterized by the combined effect of hydraulic, chemical, thermal and electro osmotic flow.     

Two-Phase Pore-Network Modelling: Existence of Oil Layers During Water Invasion

Pore-network modelling is commonly used to predict capillary pressure and relative permeability functions for multi-phase flow simulations. These functions strongly depend on the presence of fluid films and layers in pore corners. Recently, van Dijke and Sorbie (J. Coll. Int. Sci. 293:455–463, 2006) obtained the new thermodynamically derived criterion for oil layers existence in the pore corners with non-uniform wettability caused by ageing. This criterion is consistent with the thermodynamically derived capillary entry pressures for other water invasion displacements and it is more restrictive than the previously used geometrical layer collapse criterion. The thermodynamic criterion has been included in a newly developed two-phase flow pore network model, as well as two versions of the geometrical criterion. The network model takes as input networks extracted from pore space reconstruction methods or CT images. Furthermore, a new n-cornered star shape characterization technique has been implemented, based on shape factor and dimensionless hydraulic radius as input parameters. For two unstructured networks, derived from a Berea sandstone sample, oil residuals have been estimated for different wettability scenarios, by varying the contact angles in oil-filled pores after ageing from weakly to strongly oil-wet. Simulation of primary drainage, ageing and water invasion show that the thermodynamical oil layer existence criterion gives more realistic oil residual saturations compared to the geometrical criteria. Additionally, a sensitivity analysis has been carried out of oil residuals with respect to end-point capillary pressures. For strongly oil-wet cases residuals increase strongly with increasing end-point capillary pressures, contrary to intermediate oil-wet cases.     

Understanding Oil and Gas Flow Mechanisms in Shale Reservoirs Using SLD–PR Transport Model

More and more attention has been paid to the oil and gas flow mechanisms in shale reservoirs. The solid–fluid interaction becomes significant when the pores are in the nanoscale. The interaction changes the fluid’s physical properties and leads to different flow mechanisms in shale reservoirs from those in conventional reservoirs. By using a Simplified Local Density–Peng Robinson transport model, we consider the density and viscosity profiles, which result from solid–fluid interaction. Gas rarefaction effect is negligible at high pressure, so we assume it is viscous flow. Considering the density- and viscosity-changing effects, we proposed a slit permeability model. The velocity profiles are obtained by this newly established model. This proposed model is validated by matching the density profile and velocity profile from molecular dynamic simulation. Then, the effects of pressure and pore size on gas and oil flow mechanisms are also studied in this work. The results show that both gas and oil exhibit enhanced flow rates in nanopores. Gas-phase flow in nanopores is dominated by the density-changing effect (adsorption), while the oil-phase flow is mainly controlled by the viscosity-changing effect. Both gas and oil permeability quickly decrease to the Darcy permeability when the slit aperture becomes large. The results reported in this work are representative and should significantly help us understand the mechanisms of oil and gas flow in shale reservoirs.     

A Mechanistic Model of Gas-Condensate Flow in Pores

Recent experimental results reported in the literature indicate that the relative permeability of gas-condensate systems increases with rate (velocity) at some conditions. To gain a better understanding of the nature of the flow and the prevailing mechanisms resulting in such behaviour flow visualisation experiments have been performed, using high pressure micromodels. The observed flow behaviour at the pore level has been employed to develop a mechanistic model describing the coupled flow of gas and condensate phases. The results of the model simulating the observed simultaneous flow of gas and condensate phases have been compared with reported core experimental results. Most features of the reported rate effect are predictable by the developed single pore model, nevertheless, its extension to include multiple pore interaction is recommended.     

Simulation of Three-Phase Displacement Mechanisms Using a 2D Lattice-Boltzmann Model

Using a numerical technique, known as the lattice-Boltzmann method, we study immiscible three-phase flow at the pore scale. An important phenomenon at this scale is the spreading of oil onto the gas–water interface. In this paper, we recognize from first principles how injected gas remobilizes initially trapped oil blobs. The two main flow mechanisms which account for this type of remobilization are simulated. These are the double-drainage mechanism and (countercurrent) film flow of oil. The simulations agree qualitatively with experimental findings in the literature. We also simulate steady-state three-phase flow (fixed and equal saturations) in a small segment of a waterwet porous medium under both spreading and nonspreading conditions. The difference between the two conditions with respect to the coefficients in the generalized law of Darcy (which also includes viscous coupling) is investigated.     

Two-Phase Flow Properties Prediction from Small-Scale Data Using Pore-Network Modeling

The objective of this work is to evaluate the prediction accuracy of network modeling to calculate transport properties of porous media based on the interpretation of mercury invasion capillary pressure curves only. A pore-scale modeling approach is used to model the multi-phase flow and calculate gas/oil relative permeability curves. The characteristics of the 3-D pore-network are defined with the requirement that the network model satisfactorily reproduces the capillary pressure curve (P_c curve), the porosity and the permeability. A sensitivity study on the effect of the input parameters on the prediction of capillary pressure and gas/oil relative permeability curves is presented. The simulations show that different input parameters can lead to similarly good reproductions of the experimental P_c, although the predicted relative permeabilities K_r are somewhat widespread. This means that the information derived from a mercury invasion P_c curve is not sufficient to characterize transport properties of a porous medium. The simulations indicate that more quantitative information on the wall roughness and the node/bond aspect ratio would be necessary to better constrain the problem. There is also evidence that in narrow pore size distributions pore body volume and pore throat radius are correlated while in broad pore size distributions they would be uncorrelated.     

Modelling Low-Salinity Oil Recovery Mechanisms Using an Ion Dissociation Model

Experimental evidence shows that injecting low-salinity water during the oil recovery process can lead to an increase in the amount of oil recovered. Numerous mechanisms have been proposed to explain this effect, and, in recent years, two which have gained notable support are multicomponent ionic exchange (MIE) and pH increase. Both mechanisms involve ion exchange reactions within the thin film of water separating the oil in a reservoir from the clay minerals on the surface of the reservoir rock. Since the reactions occur on the molecular scale, an upscaled model is required in order to accurately determine the dominant mechanism using centimetre-scale experiments. In this paper, we develop the first stages of this upscaling process by modelling the pore-scale motion of an oil slug through a clay pore throat. We use a law-of-mass-action approach to model the exchange reactions occurring on the oil–water and clay–water interfaces in order to derive expressions for the surface charges as functions of the salinity. By balancing the disjoining pressure in the water film with the capillary pressure across the oil–water interface, we derive an expression for the salinity-dependent film thickness. We compare the two mechanisms by modifying an existing model for the velocity of an oil slug through a pore throat. Numerical results show that the velocity increases as the salinity decreases. The percentage increase is larger for the MIE mechanism, suggesting that MIE may be the dominant causal mechanism; however, this will vary depending on the particular clay and oil being studied.

     

Simulation of two generalised Newtonian fluids flow in micropore with dead end

This research deals with the numerical simulation of Carreau and power-law fluids flow in an open capillary of a reservoir. The capillary is connected to a dead end. The finite volume method (FVM) on a structured and co-located grid has been used. The numerical method has been validated through the comparison of numerical results against the analytical solutions of power-law fluid flow in a planar channel. The effects of fluids, the operating conditions and the aspect ratio of dead end at the low Reynolds (Re) numbers on the oil sweeping from the dead end are investigated. The simulation results show that by increasing the power-law exponent in the case of power-law fluids, the swept depth in the dead end increases. However, according to the results, the effect of Re number on the flow pattern and the oil sweeping from the dead end is insignificant at the investigated conditions. In the case of Carreau model, at the conditions investigated, the swept area increases as the power-law exponent increases, but the Reynolds number has still minor effects on the flow pattern. Also, as the aspect ratio of dead end increases, the sweep efficiency increases.     

Experimental Study of Bacterial Penetration into Chalk Rock: Mechanisms and Effect on Permeability

Bacterial selective plugging is one of the mechanisms through which microorganisms can be applied for enhanced oil recovery, as bacteria can plug the water-swept zones of a reservoir, thus altering the flow paths and improving sweep efficiency. However, complete understanding of the penetration behavior of bacteria is lacking, especially in chalk formations where characteristic pore throat sizes are comparable with the sizes of bacterial cells. In this study, two bacterial strains, Bacillus licheniformis 421 (spore-forming) and Pseudomonas putida K12 (non-spore forming) were used to investigate the penetration of bacteria into chalk and its effect on permeability reduction. The core plugs were produced from Stevns Klint outcrop with low permeability (2–4 mD) and with pore sizes comparable to bacterial sizes. Both types of bacteria were able to penetrate and to be transported through the cores to some extent. A significantly higher number of B. licheniformis 421 was detected in the effluents as compared to P. putida K12. It was demonstrated that the spore-forming B. licheniformis 421 penetrates in the form of spores. P. putida K12 is found to penetrate the core, however, in smaller numbers compared to B. licheniformis. It was shown that both bacteria, under different injection concentrations, were capable of plugging the porous rock, as indicated by reduction of the core permeability. An incubation period of 12 days did not allow the permeability to return to initial condition. Based on the results it can be concluded that, when injected into chalk, spore forming bacteria have higher chance to survive and penetrate into deeper formation; and both types of bacteria may cause permeability reduction.     

Pore Scale and Macroscopic Displacement Mechanisms in Emulsion Flooding

The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control.