The Effect of Reservoir Wettability on the Production Characteristics of the VAPEX Process: An Experimental Study

The impact of fractional wettability on the production characteristics of a VAPEX process at the macroscale was investigated. Conventional VAPEX experiments were conducted in a 220 Darcy random packing of glass beads in a rectangular physical model and n-pentane was used to recover the Cold Lake bitumen from the oil-saturated model in the absence of connate water. The composition of oil-wet beads in the packed bed was altered from completely water-wet beads to completely oil-wet beads at different proportions of oil-wet beads mixed with water-wet beads. A substantial increase (about 40%) in the production rate of live oil was observed during the VAPEX process when the wettability of the porous packing was entirely oil-wet beads. A critical oil-wet fraction of 0.66 was found for the heterogeneous packing of water-wet and oil-wet beads of similar size distribution. Above this critical composition, the live oil production rate was not affected by further increase in the proportion of the oil-wet beads. It is believed that above this critical composition of the oil-wet beads, the crevice flow process is dominated by the continuity of higher conductivity live oil films between particles through the oil-wet regions. Below this critical composition, the live oil production rate increased linearly with the fraction of the oil-wet beads in the packing. The oil-wet regions favor the live oil drainage compared to that of the water-wet regions as they enhance the rate of imbibition of the live oil from the oil-filled pores to the vacated pores near the nominal VAPEX interface. These two factors enhance the live oil production rate during the VAPEX process. The solvent content of the live oil, the solvent-to-oil ratio (SOR), and the residual oil saturation did not correlate strongly with the proportion of the oil-wet beads in the packing. The average solvent content of the live oil and the residual oil saturation were measured to be 48% by weight and 7% by volume respectively.     

Study of Microscopic and Macroscopic Displacement Behaviors of Polymer Solution in Water-Wet and Oil-Wet Media

Performance of a polymer flood process requires the knowledge of rheological behavior of the polymer solution and reservoir properties such as rock wettability. To provide a better understanding of effects of polymer chemistry and wettability on the performance of a polymer flood process, a comprehensive experimental study was conducted using a two-dimensional glass micromodel. A series of water and polymer flood processes were carried out at different polymer molecular weights, degrees of polymer hydrolysis, and polymer concentrations in both water-wet and oil-wet systems. Image processing technique was applied to analyze and compare microscopic and macroscopic displacement behaviors of polymer solution in each experiment. From micro-scale observations, the configuration of connate water film, polymer solution trapping, flow of continuous and discontinuous strings of polymer solution, piston-type displacement of oil, snap-off of polymer solution, distorted flow of polymer solution, emulsion formation, and microscopic pore-to-pore sweep of oil phase were observed and analyzed in the strongly oil-wet and water-wet media. Rheological experiments showed that a higher polymer molecular weight, degree of hydrolysis, and concentration result in a higher apparent viscosity for polymer solution and lower oil–polymer viscosity ratio. It is also shown that these parameters have different impacts on the oil recovery in different wettabilities. Moreover, a water-wet medium generally had higher recovery in contrast with an oil-wet medium. This experimental study illustrates the successful application of glass micromodel techniques for studying enhanced oil recovery (EOR) processes in five-spot pattern and provides a useful reference for understanding the displacement behaviors in a typical polymer flood process.     

Pore-Scale Monitoring of Wettability Alteration by Silica Nanoparticles During Polymer Flooding to Heavy Oil in a Five-Spot Glass Micromodel

It is well known that the oil recovery is affected by wettability of porous medium; however, the role of nanoparticles on wettability alteration of medium surfaces has remained a topic of debate in the literature. Furthermore, there is a little information of the way dispersed silica nanoparticles affect the oil recovery efficiency during polymer flooding, especially, when heavy oil is used. In this study, a series of injection experiments were performed in a five-spot glass micromodel after saturation with the heavy oil. Polyacrylamide solution and dispersed silica nanoparticles in polyacrylamide (DSNP) solution were used as injected fluids. The oil recovery as well as fluid distribution in the pores and throats was measured with analysis of continuously provided pictures during the experiments. Sessile drop method was used for measuring the contact angles of the glass surface at different states of wettability after coating by heavy oil, distilled water, dispersed silica nanoparticles in water (DSNW), polyacrylamide solution, and DSNP solution. The results showed that the silica nanoparticles caused enhanced oil recovery during polymer flooding by a factor of 10%. The distribution of DSNP solution during flooding tests in pores and throats showed strong water-wetting of the medium after flooding with this solution. The results of sessile drop experiments showed that coating with heavy oil, could make an oil-wet surface. Coating with distilled water and polymer solution could partially alter the wettability of surface to water-wet and coating with DSNW and DSNP could make a strongly water-wet surface.     

A Parametric Model for Predicting Relative Permeability-Saturation-Capillary Pressure Relationships of Oil–Water Systems in Porous Media with Mixed Wettability

A parametric two-phase, oil–water relative permeability/capillary pressure model for petroleum engineering and environmental applications is developed for porous media in which the smaller pores are strongly water-wet and the larger pores tend to be intermediate- or oil-wet. A saturation index, which can vary from 0 to 1, is used to distinguish those pores that are strongly water-wet from those that have intermediate- or oil-wet characteristics. The capillary pressure submodel is capable of describing main-drainage and hysteretic saturation-path saturations for positive and negative oil–water capillary pressures. At high oil–water capillary pressures, an asymptote is approached as the water saturation approaches the residual water saturation. At low oil–water capillary pressures (i.e. negative), another asymptote is approached as the oil saturation approaches the residual oil saturation. Hysteresis in capillary pressure relations, including water entrapment, is modeled. Relative permeabilities are predicted using parameters that describe main-drainage capillary pressure relations and accounting for how water and oil are distributed throughout the pore spaces of a porous medium with mixed wettability. The capillary pressure submodel is tested against published experimental data, and an example of how to use the relative permeability/capillary pressure model for a hypothetical saturation-path scenario involving several imbibition and drainage paths is given. Features of the model are also explained. Results suggest that the proposed model is capable of predicting relative permeability/capillary pressure characteristics of porous media mixed wettability.     

Effect of Organosilicon-Acrylic Emulsion Treatment on Wettability of Porous Media

To investigate the influence of the organosilicon-acrylic on wetting properties of porous media, contact angle tests were performed on two different sandstones. In addition, the effectiveness of the emulsion on wettability alteration of porous media was validated by capillary rise and spontaneous imbibition tests. The results of wettability tests showed that the wettability of two sandstones was altered from water-wet to gas-wet after treatment with the emulsion. The principle that the critical radius of pore throats and wettability of porous media affect liquids flow was derived analytically and verified experimentally. Coreflood results demonstrated that the latex resulted in increasing the water permeability through altering the rock wettability to gas-wetting, then decreasing the friction drag between liquids and rocks surface. Thereby, the emulsion treatment could increase the flowback rate of trapped liquids. Experimental results were in good agreement with the theoretical analysis. In conclusion, all results indicated that the emulsion could alter the wettability from water-wet to intermediate gas-wet and enhance water permeability in porous media. It was extrapolated that the emulsion had the tremendous potential to be applied in field conditions, enhancing gas productivity through the cleanup of trapped water in the vicinity of the wellbore.     

Pore-Scale Imaging and Analysis of Wettability Order,Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤?1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

     

Unified Model of Drainage and Imbibition in 3D Fractionally Wet Porous Media

We develop a grain-based model for capillarity controlled displacement within 3D fractionally wet porous media. The model is based on a novel local calculation of the position of stable fluid–fluid interfaces in contact with multiple spherical grains of arbitrary contact angles. The interface is assumed to be locally spherical between bulk phases; the interface is assumed to be toroidal between pairs of grains (surfaces of pendular rings). Because the calculation of interface position is entirely local and grain-based, it provides a single, generalized, geometric basis for computing pore-filling events during drainage as well as imbibition with both Melrose events (merging of two interfaces) and Haines events (geometric instability). The model is validated against a series of drainage/imbibition experiments (oil/water) on fractionally wet porous media prepared by mixing oil-wet grains with water-wet grains.     

Pore-scale Simulation of Water Alternate Gas Injection

We use a three-dimensional mixed-wet random network model representing Berea sandstone to compute displacement paths and relative permeabilities for water alternating gas (WAG) flooding. First we reproduce cycles of water and gas injection observed in previously published experimental studies. We predict the measured oil, water and gas relative permeabilities accurately. We discuss the hysteresis trends in the water and gas relative permeabilities and compare the behavior of water-wet and oil-wet media. We interpret the results in terms of pore-scale displacements. In water-wet media the water relative permeability is lower during water injection in the presence of gas due to an increase in oil/water capillary pressure that causes a decrease in wetting layer conductance. The gas relative permeability is higher for displacement cycles after first gas injection at high gas saturation due to cooperative pore filling, but lower at low saturation due to trapping. In oil-wet media, the water relative permeability remains low until water-filled elements span the system at which point the relative permeability increases rapidly. The gas relative permeability is lower in the presence of water than oil because it is no longer the most non-wetting phase.     

Prediction of Microscopic Remaining Oil Distribution Using Fuzzy Comprehensive Evaluation

A network model is established through the techniques of image reconstruction, a thinning algorithm, and pore–throat information extraction with the aid of an industrial microfocus CT scanning system. In order to characterize actual rock pore–throat structure, the established model is modified according to the matching of experimental factors such as porosity, permeability, and the relative permeability curve. On this basis, the impacts of wetting angle, pore radius, shape factor, pore–throat ratio, and coordination number as applied to microscopic remaining oil distribution after water flooding are discussed. For a partially wetting condition, the displacement result of a water-wet pore is somewhat better than that of an oil-wet pore as a whole, and the possibility of any remaining oil is relatively low. Taking the comprehensive effects of various factors into account, a prediction method of remaining oil distribution is presented through the use of fuzzy comprehensive evaluation. It is seen that this method can predict whether there is remaining oil or not in the pore space with satisfactory accuracy, which is above 75%. This method thus provides guidance for a better understanding of the microscopic causes of the remaining oil.     

A Dynamic Network Model for Two-Phase Flow in Porous Media

We present a dynamic model of immiscible two-phase flow in a network representation of a porous medium. The model is based on the governing equations describing two-phase flow in porous media, and can handle both drainage, imbibition, and steady-state displacement. Dynamic wetting layers in corners of the pore space are incorporated, with focus on modeling resistivity measurements on saturated rocks at different capillary numbers. The flow simulations are performed on a realistic network of a sandpack which is perfectly water-wet. Our numerical results show saturation profiles for imbibition in agreement with experiments. For free spontaneous imbibition we find that the imbibition rate follows the Washburn relation, i.e., the water saturation increases proportionally to the square root of time. We also reproduce rate effects in the resistivity index for drainage and imbibition.     

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.     

Numerical simulation of pore-scale flow in chemical flooding process

Chemical flooding is one of the effective technologies to increase oil recovery of petroleum reservoirs after water flooding. Above the scale of representative elementary volume (REV), phenomenological modeling and numerical simulations of chemical flooding have been reported in literatures, but the studies alike are rarely conducted at the pore-scale, at which the effects of physicochemical hydrodynamics are hardly resolved either by experimental observations or by traditional continuum-based simulations. In this paper, dissipative particle dynamics (DPD), one of mesoscopic fluid particle methods, is introduced to simulate the pore-scale flow in chemical flooding processes. The theoretical background, mathematical formulation and numerical approach of DPD are presented. The plane Poiseuille flow is used to illustrate the accuracy of the DPD simulation, and then the processes of polymer flooding through an oil-wet throat and a water-wet throat are studies, respectively. The selected parameters of those simulations are given in details. These preliminary results show the potential of this novel method for modeling the physicochemical hydrodynamics at the pore scale in the area of chemical enhanced oil recovery.     

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.     

Pore-Scale Lattice Boltzmann Modeling and 4D X-ray Computed Microtomography Imaging of Fracture-Matrix Fluid Transfer

We present sequential X-ray computed microtomography (CMT) images of matrix drainage in a fractured, sintered glass-granule-pack. Sequential (4D) CMT imaging captured the capillary-dominated displacement of the oil-occupied matrix by the surfactant-brine-occupied fracture at the pore scale. The sintered glass-granule-pack was designed to have minimal pore space beyond the resolution of CMT imaging, ensuring that the pore space of the matrix connected to the fracture could be captured in its entirety. This provided an opportunity to validate the increasingly common lattice Boltzmann modeling technique against experimental images at the pore scale. Although the surfactant was found to alter the wettability of the originally weakly oil-wet glass to water-wet, the fracture-matrix fluid transfer is found to be a drainage process, showing minimal counter-current migration of the initial wetting phase (decane). The LB simulations were found to closely match experimental rates of fracture-matrix fluid transfer, and trends in the saturation profiles, but not the irreducible wetting-phase saturation behind the flooding front. The underestimation of the irreducible wetting phase saturation suggests that finer image and lattice resolutions than those reported here may be required for accurate prediction of some macroscale multiphase flow properties, at a sizable computational cost.     

Correction to: Time and Space Fractional Diffusion in Finite Systems

Additive manufacturing technology, or 3D printing, with silica sand has enabled the manufacture of porous rock analogues for the use in experimental studies of geomechanical properties of reservoir rocks. The accurate modelling of the fluid flow phenomena within a reservoir and improving the performance of hydrocarbon recovery require an understanding of physical and chemical interactions of the reservoir fluids and the rock matrix. Therefore, for the 3D printed samples to serve as rock analogues, flow properties have to be equivalent to the petrophysical properties of their natural counterparts, such as Berea sandstone. In this study, sandstones that were 3D printed with silica sand and Poly-Furfuryl alcohol (PFA) binder, were used to investigate interactions between porous media with different fluids. Wettability preference of 3D printed samples was characterized through contact angle measurements, as well as co-current and counter-current spontaneous imbibition experiments. Results indicated that 3D printed sandstones had mixed-wet characteristics due to the high preference of silica grains for polar fluids and the affinity PFA binder to the oleic phase. Printing configurations including binder saturation were found to greatly influence the wettability preference of the 3D printed analogue rocks as higher PFA concentrations resulted in more strongly oil-wet preferences. Efforts to optimize the printing process and challenges to control the wettability preferences of the 3D printed samples are also highlighted.

     

Accurate Modelling of Pore-Scale Films and Layers for Three-Phase Flow Processes in Clastic and Carbonate Rocks with Arbitrary Wettability

Three-phase flow is a key process occurring in subsurface reservoirs, for example, during $\text{ CO }_2$ sequestration and enhanced oil recovery techniques such as water alternating gas (WAG) injection. Predicting three-phase flow processes, for example, the increase in oil recovery during WAG, requires a sound understanding of the fundamental flow physics in water- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this study, we use pore-network modelling, a reliable and physically based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from water- to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows for the accurate modelling of the mobilisation of many disconnected phase clusters that arise, in particular, during higher order WAG floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the sample. For water-wet systems, we have validated our model with available experimental data from core floods. For oil-wet systems, we validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.     

A Percolation Study of Wettability Effect on the Electrical Properties of Reservior Rocks

Measurements of the electrical resistivity of oil reservoirs are commonly used to estimate other properties of reservoirs, such as porosity and hydrocarbon reserves. However, the interpretation of the measurements is based on empirical correlations, because the underlying mechanisms that control the electrical properties of oil bearing rocks have not been well understood. In this paper, we employ percolation concepts to investigate the effect of wettability on the electrical conductivity of a reservoir formation. A three-dimensional simple cubic network is used to represent an ideal reservoir formation, for which the effect of the wettability can be isolated from the others. The phase distribution in the network is analyzed for different flow processes, and the conductivity is then estimated using a power law approximation of the percolation quantities.To whom correspondence should be addressed.The proposed conceptual model predicts the generic behavior of reservoir resistivities of different wettabilities. It demonstrates that the resistivity index depends on saturation history and wettability. For strongly oil-wet systems, significant hysteresis is expected, while there is little hysteresis for strongly water-wet systems, and some hysteresis is also expected for intermediate wet systems. One of the interesting results from this study is that for intermediate wet systems, Archie's saturation exponent is between 1.9 and 3.0.Chemical Engineering Department, Technical University of Denmark, DK-2800 Lyngby, Denmark.     

Effect of Wetting on the Dynamics of Drainage in Porous Media

We examine the consequences of the wettability properties on the dynamics of gravity drainage in porous media. The relation between the wetting properties at the pore scale and the macroscale hydrodynamics is studied. Model porous media consisting of hydrophilic and hydrophobic glass beads or sand with well defined wetting properties, are prepared for this study. Gravity drainage experiments with air displacing water (two-phase flow), are performed for different Bond numbers, and using different techniques such as gamma-ray densitometry, magnetic resonance imaging (MRI) and weight measurements. The dynamics of drainage is found to be different for hydrophilic and hydrophobic porous media in the transition zone (funicular regime). Moreover, for hydrophilic (water-wet) porous media, MRI experiments reveal the importance of drainage through the continuous water film, which leads to an increase of the residual quantity of water in the transition zone with time.     

Experimental investigation of capillary pressure effects on immiscible displacement in lensed and layered porous media

This paper reports the results of extensive experimental studies of the effects of well-defined heterogeneous porous media on immiscible flooding. The heterogeneities were layers and lenses, with some of the lenses being a wettability contrast. Drainage and imbibition displacements, with and without an initial residual fluid saturation, were carried out at a variety of flow rates on layered and lensed two-dimensional glass beads models of the size of a typical large core test (58×10×0.6 cm). These displacements were followed photographically and the effluent saturation profiles recorded. In most of the experiments the glass beads were water-wet, but in some the lens beads were coated with a water repellent chemical. In all experiments, the displacement fronts became highly irregular due to the different capillary pressures acting in the different areas of the models. In this paper, these displacements are fully reported and their implications for reservoir simulation and for interpretation of laboratory core tests, where the inner heterogeneities are not known, are discussed.     

Dissipative particle dynamics simulation of wettability alternation phenomena in the chemical flooding process

Wettability alternation phenomena is considered one of the most important enhanced oil recovery （EOR） mechanisms in the chemical flooding process and induced by the adsorption of surfactant on the rock surface. These phenomena are studied by a mesoscopic method named as dissipative particle dynamics （DPD）. Both the alteration phenomena of water-wet to oil-wet and that of oil-wet to water-wet are simulated based on reasonable definition of interaction parameters between beads. The wetting hysteresis phenomenon and the process of oil-drops detachment from rock surfaces with different wettability are simulated by adding long-range external forces on the fluid particles. The simulation results show that, the oil drop is liable to spread on the oil-wetting surface and move in the form of liquid film flow, whereas it is likely to move as a whole on the waterwetting surface. There are the same phenomena occuring in wettability-alternated cases. The results also show that DPD method provides a feasible approach to the problems of seepage flow with physicochemical phenomena and can be used to study the mechanism of EOR of chemical flooding.