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.     

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.     

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.     

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.     

Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Most clastic reservoirs display an intermediate type of wettability. Intermediate wettability covers several local wetting configurations like fractional wet and mixed-wet where the oil-wet sites could either be in the large or smaller pores. Clastic reservoirs show a large variation in fluid flow properties. A classical invasion–percolation network simulator is used to investigate properties of different intermediate wet situations. Variation in wetting properties like contact angles, process dependent contact angles, contact angle distribution, and fraction of oil wet sites are investigated. The fluid flow properties analysed in particular are residual oil saturation and normalized endpoint relative permeability. Results from network modelling have been compared to reservoir core analysis data. The network models applied are at the capillary limit, while the core flood results are clearly viscous influenced. Even though network modelling does not cover all the physics involved in fluid displacement processes, results show that data from simulations are sufficient to present trends in fluid flow properties which are comparable to experimental data.     

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 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.

     

The Effect of Heavy Oil Viscosity Reduction by Solvent Dissolution on Natural Convection in the Boundary Layer of VAPEX

We have studied the effect of viscosity on natural convection in the boundary layer of the vapor extraction (VAPEX) process. VAPEX is a heavy oil recovery method that uses solvents to reduce oil viscosity, and is a potential process in reservoirs where thermal recovery methods cannot be applied. Natural convection may happen in VAPEX if the solvents that are used to decrease oil viscosity increase the density of the oil. This can especially occur with $\text{ CO }_{2}$ CO 2 -based solvents. Reduction of the oil viscosity due to solvent dissolution can have a large impact on the onset of convection by decreasing the critical Rayleigh number. When the viscosity reduction is significant, the critical Rayleigh can decrease up to two orders of magnitude. The transverse Peclet number is also a crucial parameter in determining the critical Rayleigh and onset of convection. Our analysis shows that the longitudinal Peclet does not have a significant impact on the natural convention in VAPEX. When oil viscosity reduction is included in the analysis of boundary layer instability in VAPEX, natural convection may occur in high-permeable reservoirs (where Rayleigh number is high) leading to a greater oil production rate compared with current models where the effect of boundary layer instability has been ignored.     

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.     

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.     

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.     

Effects of Precursor Wetting Films in Immiscible Displacement Through Porous Media

A computer-aided simulator of immiscible displacement in strongly water-wet consolidated porous media that takes into account the effects of the wetting films is developed. The porous medium is modeled as a three-dimensional network of randomly sized unit cells of the constricted-tube type. Precursor wetting films are assumed to advance through the microroughness of the pore walls. Two types of pore wall microroughness are considered. In the first type of microroughness, the film advances quickly, driven by capillary pressure. In the second type, the meniscus moves relatively slowly, driven by local bulk pressure differences. In the latter case, the wetting film often forms a collar that squeezes the thread of oil causing oil disconnection. Each pore is assumed to have either one of the aforementioned microroughness types, or both. The type of microroughness in each pore is assigned randomly. The simulator is used to predict the residual oil saturation as a function of the pertinent parameters (capillary number, viscosity ratio, fraction of pores with each type of wall microroughness). These results are compared with those obtained in the absence of wetting films. It is found that wetting films cause substantial increase of the residual oil saturation. Furthermore, the action of the wetting films causes an increase of the mean volume of the residual oil ganglia.     

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.     

The Effect of Wettability on Three-Phase Relative Permeability

We study three-phase flow in water-wet, oil-wet, and fractionally-wet sandpacks. We use CT scanning to measure directly the oil and water relative permeabilites for three-phase gravity drainage. In an analogue experiment, we measure pressure gradients in the gas phase to determine the gas relative permeability. Thus we find all three relative permeabilities as a function of saturation. We find that the gas relative permeability is approximately half as much in a oil-wet medium than in an water-wet medium at the same gas saturation. The water relative permeability in the water-wet medium and the oil relative permeability in the oil-wet medium are similar. In the water-wet medium the oil relative permeability scales as k _roS _o ⁴ for S _o>S _or, where S _or is the waterflood residual oil saturation. With octane as the oil phase, k _roS _o ² for S _o<S _or, while with decane as the oil phase, k _ro falls sharply for S _o<S _or. The water relative permeability in the oil-wet medium resembles the oil relative permeability in the water-wet medium for a non-spreading oil such as decane. These observations can be explained in terms of wetting, spreading, and the pore scale configurations of fluid.     

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.     

Radial Oil–Water Transport Toward an Extraction Well

We apply steady-state capillary-controlled upscaling in heterogeneous environments. A phase may fail to form a connected path across a given domain at capillary equilibrium. Moreover, even if a continuous saturation path exists, some regions of the domain may produce disconnected clusters that do not contribute to the overall connectivity of the system. In such cases, conventional upscaling processes might not be accurate since identification and removal of these isolated clusters are extremely important to the global connectivity of the system and the stability of the numerical solvers. In this study, we address the impact of percolation during capillary-controlled displacements in heterogeneous porous media and present a comprehensive investigation using random absolute permeability fields, for water-wet, oil-wet and mixed-wet systems, where J-function scaling is used to relate capillary pressure, porosity and absolute permeabilities in each grid cell. Important information is revealed about the average connectivity of the phases and trapping at the Darcy scale due to capillary forces. We show that in oil-wet and mixed-wet media, large-scale trapping of oil controlled by variations in local capillary pressure may be more significant than the local trapping, controlled by pore-scale displacement.     

An Analytical Model for Determination of the Solvent Convective Dispersion Coefficient in the Vapor Extraction Heavy Oil Recovery Process

In this article, a new model is developed to determine the solvent convective dispersion coefficient in a solvent vapor extraction (VAPEX) heavy oil recovery process. It is assumed that solvent mass transfer by convective dispersion takes place along the transition zone between the solvent chamber and untouched heavy oil, whereas solvent mass transfer by molecular diffusion occurs in the direction normal to the transition zone. It is also assumed that the solvent-diluted heavy oil gravity drainage through the transition zone has a linear or quadratic velocity profile in order to obtain analytical solutions of the solvent convective dispersion coefficients for the solvent chamber spreading and falling phases. As a result, this analytical model correlates the solvent convective dispersion coefficient to the maximum apparent oil gravity drainage velocity at the interface between the solvent chamber and transition zone, solvent molecular diffusion coefficient, transition-zone thickness, and porosity of the porous medium. To determine the solvent convective dispersion coefficient, the maximum apparent oil gravity drainage velocity is calculated by using Darcy’s law and the transition-zone thickness is obtained either from a previous study or by using a time similarity between the solvent molecular diffusion and oil gravity drainage. It is found that such a determined solvent convective dispersion coefficient is two to five orders larger than the solvent molecular diffusion coefficient, depending on the detailed experimental conditions of a specific VAPEX test.     

Unstable Immiscible Displacements in Oil-Wet Rocks

Displacement of a viscous fluid by a lower viscosity immiscible fluid (such as waterflood of a viscous oil) in a porous medium is unstable. The displacement front generates viscous fingers which lead to low oil recovery efficiency. These fingers are much smaller in width than typical reservoir simulation grid blocks, and capturing their effect in reservoir simulation is important. A dimensionless scaling group (viscous finger number) had been suggested in the past, which has a power-law relationship with the breakthrough recovery and cumulative recovery in unstable core floods. The relative permeability used in large grid block simulations had been modified to so-called pseudo-relative permeability on the basis of the dimensionless group, thus incorporating the effect of fingers in waterflood predictions. However, the previous proposed models were constructed from experiments in only water-wet rocks. This paper extends the recent viscous fingering models to oil-wet systems. Sandstone cores were treated to alter the wettability to oil-wet. Adverse viscosity water floods were performed in oil-wet cores. Viscosity ratio, velocity and diameter were varied. It is shown that the previously developed viscous finger number does not work for the oil-wet experiments. The correlating dimensionless number is modified for oil-wet systems; it is also different from the dimensionless group identified by Peters and Flock (Soc Petroleum Eng, 1981. doi: 10.2118/8371-PA) for oil-wet cores. A pseudo-relative permeability model has been developed for oil-wet cores. Corefloods have been matched by the new pseudo-relative permeability model to determine the model parameters. This pseudo-relative permeability model can be used in reservoir simulations of water and polymer floods in viscous oil-wet reservoirs.     

Coreflooding Studies to Evaluate the Impact of Salinity and Wettability on Oil Recovery Efficiency

In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of experiments) with decrease in brine salinity and increase in brine temperature.