Counter-current Imbibition Research Articles

Imbibition oil recovery from tight rocks with dual-wettability behavior

Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated plugs in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the oil recovery data from the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition tests on dry samples suggest that affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and counter-current imbibition tests suggest that affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil.

Pore-level influence of micro-fracture parameters on visco-capillary behavior of two-phase displacements in porous media

Abstract In this work, coupled Cahn–Hilliard phase field and Navier–Stokes equations were solved using finite element method to address the effects of micro-fracture and its characterizations on water-oil displacements in a heterogeneous porous medium. Sensitivity studies at a wide range of viscosity ratios (M) and capillary numbers (Ca), and the resultant log Ca–log M stability phase diagram, revealed that in both media, with/without fracture, the three regimes of viscous fingering, capillary fingering and stable displacement similarly occur. However, presence of the fracture caused water channeling phenomenon which resulted in reduction of the number of active fingers and hence the final oil recovery factor. At high Ca (especially in the stable regime, with log Ca ≥ −2.5 and log M ≥ 0), recovery factor for the fractured medium was relatively identical with the non-fractured one. At log M ≥ 0, the fracture was fully swept, but flow instabilities were observed inside the fracture at lower M values, especially for log Ca > −4.6. In the case of the fractured medium at log Ca = −4.6 and log M = 0 (capillary dominant flow), it is observed that the primary breakthrough took place by a finger progressed through the matrix, not those channeled through the fracture. Geometrical properties of the fracture, including length, aperture and orientation, highly affected both displacement profile and efficiency. The fracture length inversely influenced the oil recovery factor. It was observed that there is a critical fracture width (almost half of the medium average pore diameter) at which the recovery factor of the medium during displacement is minimum, compared to the media having thinner and thicker fractures. Minor channeling effect in the media with thinner fracture and larger fracture swept volume as well as high fracture/matrix cross flow in the media with thicker fracture were detected as the main cause of this non-monotonic behavior. In the models with thick fractures (with the thickness higher than the average pore diameter), considerable trapped oil volumes were observed inside the fracture at low M values. The fracture orientation had the most impressive effect on oil recovery compared to the other studied parameters; where the oil recovery factor incremented more than 20% as the fracture rotated 90° from flow direction. Due to the dominant effect of the channeling phenomenon, the change in the medium wettability from slightly oil-wet to slightly water-wet, did not considerably affect the displacement profile in the fractured medium. However, oil recovery factor increased as the medium became more water-wet. The fracture area was fully swept by the injected water in the oil-wet and neutral-wet media. However, flow instabilities were observed inside the fracture of the water-wet medium due to counter-current imbibition between fracture/matrix. Micro-scale mechanisms of pore doublet effect, interface coalesce, snap-off and reverse movements were captured during the studied unstable displacements.

Improvements in scaling of counter-current imbibition recovery curves using a shape factor including permeability anisotropy

Spontaneous imbibition is the main oil production mechanism in the water invaded zone of a naturally fractured reservoir (NFR). Different scaling equations have been presented in the literature for upscaling of core scale imbibition recovery curves to field scale matrix blocks. Various scale dependent parameters such as gravity effects and boundary influences are required to be considered in the upscaling process. Fluid flow from matrix blocks to the fracture system is highly dependent on the permeability value in the horizontal and vertical directions. The purpose of this study is to include permeability anisotropy in the available scaling equations to improve the prediction of imbibition assisted oil production in NFRs. In this paper, a commercial reservoir simulator was used to obtain imbibition recovery curves for different scenarios. Then, the effect of permeability anisotropy on imbibition recovery curves was investigated, and the weakness of the existing scaling equations for anisotropic rocks was demonstrated. Consequently, an analytical shape factor was introduced that can better scale all the curves related to anisotropic matrix blocks.

Numerical investigation on the effect of boundary conditions on the scaling of spontaneous imbibition

We present a numerical validation of the scaling group presented by Schmid and Geiger ((2012) Water Resour. Res. 48, 3) for Spontaneous Imbibition (SI) through simulating a core sample bounded by the wetting fluid. We combine the results of the simulations with the semi-analytical model for counter-current spontaneous imbibition presented by Schmid et al. ((2011) Water Resour. Res. 47, 2) to validate the upscaling of laboratory experiments to field dimensions using dimensionless time. We then present a detailed parametric study on the effect of Boundary Conditions (BC) and characteristic length to compare imbibition assisted oil recovery with several types of boundary conditions. We demonstrate that oil recovery was the fastest and most efficient when all faces are open to flow. We also demonstrate that all cases scale with the non-dimensionless time suggested by Schmid and Geiger ((2012) Water Resour. Res. 48, 3) and show a close match to the numerical simulation and the semi-analytical solution. Moreover, we discuss how the effect of constructing a model with varying grid sizes and dimensions affects the accuracy of the results through comparing the results of the 2-D and 3-D models. We observe that the 3-D model proved superior in the accuracy of the results to simulate simple counter-current SI. However, we deduce that 2-D models yield satisfying enough results in a timely manner in the One End Open (OEO) and Two Ends Open (TEO) cases, compared to 3-D models which are time-consuming. We finally conclude that the non-dimensionless time of Schmid and Geiger ((2012) Water Resour. Res. 48, 3) works well with counter-current SI cases regardless of the boundary condition imposed on the core.

Numerical simulation of counter-current spontaneous imbibition in water-wet fractured porous media: Influences of water injection velocity, fracture aperture, and grains geometry

Counter-current spontaneous imbibition (SI), in which water and oil flow through the same face in opposite directions, is known as one of the most significant oil recovery mechanisms in naturally fractured reservoirs; however, this mechanism has not received much attention. Understanding the dynamic of water-oil displacement during counter-current SI is very challenging because of simultaneous impacts of multiple factors including geometry complexity and heterogeneity of naturally fractured reservoir materials, e.g., high permeability contrast between the rock matrix and fracture, wettability, and porosity. This study investigates the effects of water injection velocity, fracture aperture, and grain shape during counter-current SI at pore-scale. A robust finite element solver is used to solve the governing equations of multiphase flow, which are the coupled Navier–Stokes and Cahn–Hilliard phase-field equations. The results showed that the case with the highest injection velocity (uinj = 5 mm/s) recovered more than 15% of the matrix oil at the early times and then reached its ultimate recovery factor. However, in the case of the lowest injection velocity, i.e., uinj = 0.05 mm/s, the lowest imbibition rate was observed at the early times, but ultimately 23% of the matrix oil was recovered. The model with uinj = 5 mm/s was able to capture some pore-level mechanisms such as snap-off, oil film thinning, interface coalescence, and water film bridging. The obtained results revealed that changing the fracture aperture has a slight effect on the imbibition rate at the earlier times and ultimate recoveries would be almost equal. To assess the influences of grain shape on the imbibition process, the simulated domain was reconstructed with cubic grains. It was noticed that because of higher permeability and porosity, relatively larger oil drops were formed and resulted in higher oil recovery compared with the model with spherical grains. The developed model can be used as a basis for phase-field counter-current simulations and would be useful to study the qualitative and quantitative nature of this phenomenon.

An investigation on surfactant aided gravity drainage in fractured reservoirs using matrix block flow simulation

Capillary and gravity forces are the controlling mechanisms in fractured reservoirs recovery. Most of the fractured reservoirs are carbonate formations with mixed wet and oil wet rocks. One of the techniques to improve the oil recovery from these reservoirs is surfactant treatment in the water invaded zone of carbonate fractured formation known as surfactant-aided gravity drainage. A number of experimental and modeling studies are available in this research area however, a modeling approach validated with the experimental data to consider different conditions in the reservoir, including rock physics, fluid properties, water salinity and surfactant functionalities is still a necessary element before the pilot tests for this recovery technique. In this work, a modeling approach is proposed to provide insight into the engineering aspects of this process. It defines a reservoir rock matrix (core scale) surrounded by the surfactant-brine solution in the fracture that acts as a boundary for the matrix in an imbibition test scenario. The reservoir rock is oil wet, therefore at first, the diffusive forces drive the solution into the matrix leading to wettability alteration. Afterwards the counter-current imbibition takes place in the early through the middle time of the experiment. Finally, the gravity drainage controls the recovery process. The parametric analysis investigates the effects of various parameters. Different modifications to the base case (validated with the experimental data) are performed for each parameter and then the resultant recovery curves are compared with the base case recovery. The parametric study shows that fluid densities, height, anisotropy ratio, permeability, connate water saturation, capillary pressure and the saturation end-points, are the main parameters influencing the performance of surfactant-aided gravity drainage. This study highlights the process sensitivity to the changes of the main effective displacement process parameters.

Simulation of counter-current imbibition in water-wet fractured reservoirs based on discrete-fracture model

Abstract Isolated fractures usually exist in fractured media systems, where the capillary pressure in the fracture is lower than that of the matrix, causing the discrepancy in oil recoveries between fractured and non-fractured porous media. Experiments, analytical solutions and conventional simulation methods based on the continuum model approach are incompetent or insufficient in describing media containing isolated fractures. In this paper, the simulation of the counter-current imbibition in fractured media is based on the discrete-fracture model (DFM). The interlocking or arrangement of matrix and fracture system within the model resembles the traditional discrete fracture network model and the hybrid-mixed-finite-element method is employed to solve the associated equations. The Behbahani experimental data validates our simulation solution for consistency. The simulation results of the fractured media show that the isolated-fractures affect the imbibition in the matrix block. Moreover, the isolated fracture parameters such as fracture length and fracture location influence the trend of the recovery curves. Thus, the counter-current imbibition behavior of media with isolated fractures can be predicted using this method based on the discrete-fracture model.

Thermally-induced wettability alteration from hot-water imbibition in naturally fractured reservoirs—Part 1: Numerical model development & 1D models

The alteration of wettability can be a key mechanism for additional oil production from hydrocarbon reservoirs worldwide. This paper models thermally-induced wettability alteration from hot-water imbibition in naturally fractured reservoirs (NFRs). Hot-water (or steam) enhanced oil recovery (EOR) in fractured reservoirs can lead to increased oil recovery by enhancing water imbibition into matrix blocks, rendering the formation more water-wet. This will increase recovery as a result of decreased oil-water interfacial tension and reduced residual oil saturation.Modeling and evaluating production mechanisms in such a process in NFRs requires an understanding of multiphase flow parameters. In this work, numerical simulation codes with finite-difference formulations were developed to couple fluid flow and heat transfer for 1D and 2D flow geometries in spontaneous imbibition. This paper examines the effect of elevated temperature on wettability by considering various initial and boundary conditions. This approach results in more accurate simulation results as the relative permeability and capillary pressure curves are updated at each time step and for each grid (or each rock-type).The results from this study confirmed: a) the rate of recovery in co-current is generally higher than that in counter-current imbibition in a hot-water imbibition process, b) changing the wetting state in matrix from intermediate- or oil-wet to more water-wet proved to increase the ultimate recovery by reducing the residual oil saturation, c) updating the kr and Pc curves vs. temperature in simulating a hot-water injection process in NFRs can be more accurate than the commercial simulators where the relative permeability and capillary pressure curves are updated based on solely their end-points.

Analysis of the Impact of Fluid Viscosities on the Rate of Countercurrent Spontaneous Imbibition

An analysis of the fundamental equation for countercurrent spontaneous imbibition (SI) for water-wet porous media has been performed based on a generalized mobility term MTGEN accounting for fluid–solid and fluid–fluid interaction developed by Andersen et al. (IOR 2017—19th European Symposium on Improved Oil Recovery, Stavenger, Norway; European Association of Geoscientists & Engineers (EAGE): Houten, The Netherlands, 2017, ). MTGEN contains an additional term in the denominator, compared to the standard mobility term for two-phase flow, resulting from fluid–fluid interaction effects, which is proportional to both fluid viscosities. Evaluating MTGEN at a characteristic water saturation S*w chosen as 0.5; a characteristic generalized mobility term, MT*GEN, was developed. MT*GEN gives rise to a new dimensionless time (tDNew) for scaling of oil recovery vs time for spontaneous countercurrent imbibition specifically addressing the impact of fluid viscosities on the rate. tDNew has been tested and compared wit...

Phase-field simulation of counter-current spontaneous imbibition in a fractured heterogeneous porous medium

Spontaneous imbibition is well-known to be one of the most effective processes of oil recovery in fractured reservoirs. However, the detailed pore-scale mechanisms of the counter-current imbibition process and the effects of different fluid/rock parameters on this phenomenon have not yet been deeply addressed. This work presents the results of a new pore-level numerical study of counter-current spontaneous imbibition, using coupled Cahn–Hilliard phase field and Navier–Stokes equations, solved by a finite element method. A 2D fractured medium was constructed consisting of a nonhomogeneous porous matrix, in which the grains were represented by an equilateral triangular array of circles with different sizes and initially saturated with oil, and a fracture, adjacent to the matrix, initially saturated with water and supported by low rate water inflow. Through invasion of water into the matrix, oil drops were expelled one by one from the matrix to the fracture, and in the matrix, water progressed by forming capillary fingerings, with characteristics corresponding to the experimental observations. The effects of wettability, viscosity ratio, and interfacial tension were investigated. In strongly water-wet matrix, with grain contact angles of θ < π/8, different micro-scale mechanisms were successfully captured, including oil film thinning and rupture, fluids’ contact line movement, water bridging, and oil drop detachment. It was notified that there was a specific grain contact angle for this simulated model, θ = π/4, above it, matrix oil recovery was negligible by imbibition, while below it, the imbibition rate and oil recovery were significantly increased by decreasing the contact angle. In simulated mixed wet models, water, coming from the fracture, just invaded the neighboring water-wet grains; the water front was stopped moving as it met the oil-wet grains or wide pores/throats. Increasing water-oil interfacial tension, in the range of 0.005-0.05 N/m, resulted in both higher rate of imbibition and higher ultimate oil recovery. Changing the water-oil viscosity ratio (M), in the range of 0.1–10, had a negligible effect on the imbibition rate, while due to co-effects of capillary fingering and viscous mobility ratio, the model with M = 1 had relatively higher ultimate oil recovery.

Simulation of counter-current imbibition in single matrix and field scale using radical integral boundary element method

During the water driving process in reservoir which has complex fracture networks, water flows in the fractures and matrix blocks are surrounded by fractures, under this circumstance, spontaneous counter-current imbibition is the dominant mechanism for oil recovery. Therefore, modelling the counter-current behavior properly is such essential when evaluate the production performance of fractured reservoir that contains large amount of water. In this paper, the Radical Integral Boundary Element Method(RIBEM) is firstly introduced to simulate spontaneous counter-current imbibition process, this method successfully transforms the governing equation of counter-current imbibition into the complete boundary integral form and thus the boundary element method can be applied to calculate counter-current imbibition rate, the core advantage of this method is that RIBEM can achieve acceptable results without the need to divid the matrix block into many subgrids, which is convinient for application and reducing a lot computational burden. The validation of RIBEM is tested both on core and field scale, simulated results are in good agreement with corresponding experiment and fine grid simulation data.

The impact of capillary backpressure on spontaneous counter-current imbibition in porous media

We investigate the impact of capillary backpressure on spontaneous counter-current imbibition. For such displacements in strongly water-wet systems, the non-wetting phase is forced out through the inlet boundary as the wetting phase imbibes into the rock, creating a finite capillary backpressure. Under the assumption that capillary backpressure depends on the water saturation applied at the inlet boundary of the porous medium, its impact is determined using the continuum modelling approach by varying the imposed inlet saturation in the analytical solution.We present analytical solutions for the one-dimensional incompressible horizontal displacement of a non-wetting phase by a wetting phase in a porous medium. There exists an inlet saturation value above which any change in capillary backpressure has a negligible impact on the solutions. Above this threshold value, imbibition rates and front positions are largely invariant. A method for identifying this inlet saturation is proposed using an analytical procedure and we explore how varying multiphase flow properties affects the analytical solutions and this threshold saturation. We show the value of this analytical approach through the analysis of previously published experimental data.

Simulation of counter-current imbibition phenomenon in a double phase flow through fracture porous medium with capillary pressure

Abstract In this paper, the counter-current imbibition phenomenon in a fracture porous media is studied and Adomian decomposition method is applied to find the saturation of wetting phase and the recovery rate of the reservoir. A simulation result is developed for the saturation of wetting phase in fracture matrix and in porous matrix for some interesting choices of parametric value to study the recovery rate of the oil reservoir with dimensionless time. This problem has a great importance in the oil recovery process.

Simulation of Counter-Current Imbibition Phenomenon with Corey’s Model in Double Phase Flow Through Heterogeneous Porous Medium with Capillary Pressure

In this paper, the counter-current imbibition phenomena with gravity, inclination effect and with Corey’s model in heterogeneous porous media is discussed and Adomian decomposition method is applied to find the saturation rate of wetting phase and the recovery rate for both medium. Finally a simulation result is developed to study the saturation and recovery rate of the oil reservoir with dimensionless time for some interesting choices of parametric data with gravity and inclination effect. This problem has a great importance in oil recovery process.

Experimental investigation on spontaneous counter-current imbibition in water-wet natural reservoir sandstone core using MRI.

Counter-current imbibition is a process whereby a wetting phase spontaneously imbibes into a porous media, displacing the non-wetting phase. This process is considered an important oil recovery mechanism during water flooding in fractured oil reservoirs. In this study, the dynamic process of counter-current imbibition for a natural reservoir sandstone core with an all-face-open boundary condition was monitored using magnetic resonance imaging (MRI). A series of images and relaxation time T1 spectra were acquired. The movement of water spontaneously entering the core sample while oil escapes, the spatial distribution of oil and water, and the in situ saturation change of oil and water in porous media can be accurately detected using MRI. MRI assists the direct evaluation of the basic mechanisms of imbibitions. Experimental results suggest the remaining oil was trapped in some large pores because of the capillary pressure, and the oil recovery in some large-pore regions is lower than that in some small-pore regions at the end of imbibition. Experimental findings show a close agreement between conventional material balance and oil recovery determined from MRI. The in situ oil recovery data agree well with the empirical models. The observations from MRI images could provide test cases to enable the development of mathematical models and to facilitate the evaluation of the proposed imbibition mechanisms. Copyright © 2016 John Wiley & Sons, Ltd.

Effect of fluid viscosity on correlation of oil recovery by linear counter-current spontaneous imbibition

Spontaneous imbibition can be the primary mechanism of oil recovery from matrix blocks in water-wet fractured reservoirs. Scaling of imbibition recovery data is of essential importance in predicting the rate of oil recovery from fractured reservoirs. The most widely used correlation function was developed by Zhang et al. (1996), in which a geometrical mean of the fluid viscosities was used to account for the variation in fluid viscosities. In this paper, the effect of fluid viscosity on the correlation of imbibition recovery data was studied. The correlated results showed that the geometrical mean of fluid viscosity in the correlation function could closely correlate the imbibition recovery curves for variation in fluid viscosity if the oil/water viscosity ratio is constant. However, the geometrical mean of fluid viscosity could only give close correlation of imbibition data for a limited range of viscosity ratios. The dimensionless time exhibits an increased trend with decreasing oil/water viscosity ratio; especially when the oil/water viscosity ratio is lower than 5. Based on the correlated results, a new correlation function was developed by modifying the viscosity term in Zhang et al. correlation function. It was validated that the new correlation function could closely correlate the calculated imbibition recovery data for variation in wide range of viscosity ratios. In addition, the correlation of experimental imbibition recovery data for variation in fluid viscosities was improved as well by use of the new correlation function to calculate the dimensionless time. However, the experimental dimensionless time seems to exhibit a slightly increased trend with the increase in oil/water viscosity ratio. The increased trend implied that there could be an implicit interaction between relative permeability and viscosity ratio.

Permeability evolution of shale during spontaneous imbibition

Shales have small pore and throat sizes ranging from nano to micron scales, low porosity and limited permeability. The poor permeability and complex pore connectivity of shales pose technical challenges to (a) understanding flow and transport mechanisms in such systems and, (b) in predicting permeability changes under dynamic saturation conditions. This study presents quantitative experimental evidence of the migration of water through a generic shale core plug using micro CT imaging. In addition, in-situ measurements of gas permeability were performed during counter-current spontaneous imbibition of water in nano-darcy permeability Marcellus and Haynesville core plugs. It was seen that water blocks severely reduced the effective permeability of the core plugs, leading to losses of up to 99.5% of the initial permeability in experiments lasting 30 days. There was also evidence of clay swelling which further hindered gas flow. When results from this study were compared with similar counter-current gas permeability experiments reported in the literature, the initial (base) permeability of the rock was found to be a key factor in determining the time evolution of effective gas permeability during spontaneous imbibition. With time, a recovery of effective permeability was seen in the higher permeability rocks, while becoming progressively detrimental and irreversible in tighter rocks. These results suggest that matrix permeability of ultra-tight rocks is susceptible to water damage following hydraulic fracturing stimulation and, while shut-in/soaking time helps clearing-up fractures from resident fluid, its effect on the adjacent matrix permeability could be detrimental.

Modelling of imbibition phenomena in two-phase fluid flow through fractured porous media

AbstractIn this paper, the counter-current imbibition phenomenon in two phase fluid through fracture porous media is discussed and Adomian decomposition method is applied to find the saturation of wetting phase and the recovery rate of the reservoir. A simulation result is developed for the saturation of wetting phase in fracture matrix and in porous matrix for some interesting choices of parametric value to study the recovery rate of the oil reservoir with dimensionless time. This problem has a great importance in the oil recovery process.

Numerical Simulation of Magnetic Nanoparticles Injection into Two–phase Flow in a Porous Medium

In this paper, the problem of magnetic nanoparticles injection into a water–oil two–phase flow under an external permanent magnetic field is investigated. The mathematical model of the problem under consideration has been developed. We treat the water-nanoparticles suspension as a miscible mixture while it is immiscible with the oil phase. The magnetized phase pressure includes an additional pressure term with the conventional thermodynamic pressure. The countercurrent imbibition flow problem is taken as an example. Physical variables including water–nanoparticles suspension saturation, nanoparticles concentration, and pore wall/throat deposited nanoparticles are investigated under the influence of the magnetic field.

Modeling and Analysis of Magnetic Nanoparticles Injection in Water-Oil Two-Phase Flow in Porous Media under Magnetic Field Effect

In this paper, the magnetic nanoparticles are injected into a water-oil, two-phase system under the influence of an external permanent magnetic field. We lay down the mathematical model and provide a set of numerical exercises of hypothetical cases to show how an external magnetic field can influence the transport of nanoparticles in the proposed two-phase system in porous media. We treat the water-nanoparticles suspension as a miscible mixture, whereas it is immiscible with the oil phase. The magnetization properties, the density, and the viscosity of the ferrofluids are obtained based on mixture theory relationships. In the mathematical model, the phase pressure contains additional term to account for the extra pressures due to fluid magnetization effect and the magnetostrictive effect. As a proof of concept, the proposed model is applied on a countercurrent imbibition flow system in which both the displacing and the displaced fluids move in opposite directions. Physical variables, including water-nanoparticles suspension saturation, nanoparticles concentration, and pore wall/throat concentrations of deposited nanoparticles, are investigated under the influence of the magnetic field. Two different locations of the magnet are studied numerically, and variations in permeability and porosity are considered.