Imbibition Capillary Pressure Curves Research Articles

A fractal model for obtaining spontaneous imbibition capillary pressure curves based on 2D image analysis of low-permeability sandstone

Spontaneous imbibition (SI) is the principal production mechanism in naturally fractured reservoirs produced by waterflooding and is essential for fluid flow characterization to predict their future performance. As an alternative to the expensive, time-consuming laboratory measurements, 2D images render a different prospect to obtain SI capillary pressure curves, especially for tight reservoirs. This paper introduces a unique approach to infer SI capillary pressure curves from 2D images through integrating image analysis and fractal theory. Using pore-related information obtained from image analysis, we properly represent the pore structure as bundles of tortuous square and triangular tubes with sinusoidally varying radii to imitate cross-sectional variation between pore bodies and throats. Moreover, we simulate the piston-like and snap-off displacement mechanisms to derive an innovative fractal SI capillary pressure model. The developed model considers the contact angle hysteresis caused by surface roughness and heterogeneity of reservoir rocks. The Mayer-Stowe-Princen (MSP) approach is implemented to compute the entry capillary pressure of piston-like displacement. The laboratory-measured porosity and permeability are utilized to determine the model's 3D-related parameters that cannot be inferred from 2D images. The model reliability is verified with the good accuracy of the predicted capillary pressure curves versus laboratory-measured data of five samples from the Liushagang and Huangliu in the South China Sea. Finally, the fundamental parameters influencing the developed SI capillary pressure model are investigated with sensitivity analysis.

The impact of heterogeneity on the capillary trapping of [formula omitted] in the Captain Sandstone.

A significant uncertainty which remains for CO2 sequestration, is the effect of natural geological heterogeneities and hysteresis on capillary trapping over different length scales. This paper uses laboratory data measured in cores from the Goldeneye formation of the Captain D Sandstone, North Sea in 1D numerical simulations to evaluate the potential capillary trapping from natural rock heterogeneities across a range of scales, from cm to 65m. The impact of different geological realisations, as well as uncertainty in petrophysical properties, on the amount of capillary heterogeneity trapping is estimated. In addition, the validity of upscaling trapping characteristics in terms of the Land trapping parameter is assessed. The numerical models show that the capillary heterogeneity trapped CO2 saturation may vary between 0 and 14% of the total trapped saturation, depending upon the geological realisation and petrophysical uncertainty. When upscaling the Land model from core-scale experimental data, using the maximum experimental Land trapping parameter could increase the expected heterogeneity trapping by a factor of 3. Conversely, depending on the form of the imbibition capillary pressure curve used in the numerical model, including capillary pressure hysteresis may reduce the heterogeneity trapping by up to 70%.

Spatial and Temporal Quantification of Spontaneous Imbibition

AbstractSpontaneous imbibition—the process of a wetting fluid displacing a nonwetting fluid purely by capillary forces—is a ubiquitous phenomenon in porous and fibrous materials. Here we present a new experimental method for quantification of spontaneous imbibition in geologic materials. This method makes it possible to perform spontaneous imbibition under elevated pressure conditions relevant to environmental and energy resource applications. Computed tomography imaging reveals a new time‐independent scaling relationship that describes local imbibition rates as a function of water saturation. Imbibition capillary pressure curves are calculated with this wetting‐phase pressure and flow rate characterization, with no assumptions about the functional form, end point behavior, or scaling factors. Calculated end point capillary pressure is nonzero, in agreement with recent pore‐scale measurements of capillary pressure of trapped nonwetting phase. This work provides a new approach and insights into trapping and remobilization of nonwetting fluids in CO2 storage reservoirs and contaminated groundwater aquifers.

New Semi‐Analytical Insights Into Stress‐Dependent Spontaneous Imbibition and Oil Recovery in Naturally Fractured Carbonate Reservoirs

AbstractFluid injection and withdrawal in a porous medium create changes in pore pressure that alter effective stresses within the medium. This leads to pore volume changes, which can be described by the poroelastic theory. These changes in pore volume can influence fluid flow processes, such as capillary diffusion and imbibition, potentially altering multiphase flow characteristics in subsurface reservoirs with a focus on oil recovery in the naturally fractured carbonate reservoirs. In this study, a semi‐analytical model is developed to analyze the impact of stress‐dependent spontaneous imbibition. The model allows us to study the influence of stress‐dependent effects on porosity, absolute permeability, relative permeability, and capillary pressure on the imbibition and oil recovery mechanisms of both intact rock and fracture in naturally fractured carbonate reservoirs. In order to capture the geomechanical interactions involved, pure compliance poroelastic definitions and nonlinear joint normal stiffness equations are used to assess the deformation of intact rock and fracture, respectively. The model shows that increasing effective confining stress shifts the imbibition capillary pressure curve upward, resulting in improved absorption of the wetting phase into the smaller pores and enhanced extraction of the nonwetting phase. Model calculations provide a rationale for how and why irreducible water saturation increases during compression of mixed‐wet carbonates and decreases in the case of initially strong water‐wet carbonates. It is also shown how higher relative permeability of the wetting phase leads to a greater diffusion of the wetting phase and improved oil recovery for the less deformed mixed‐wet rock.

Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated.The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus.The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback.The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane.The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.

Analysis of capillary pressure and relative permeability hysteresis under low-salinity waterflooding conditions

In this work, we analyze measurements of drainage, spontaneous imbibition and forced imbibition capillary pressure curves in conjunction with two-electrode resistivity on sandstone core samples under low- and high-salinity waterflooding conditions. State-of-the-art laboratory equipment able to work with actual reservoir fluids at reservoir conditions was designed and built to conduct these measurements. Unsteady-state coreflooding experiments under similar experimental conditions to those in the capillary pressure tests were also carried out. A black-oil reservoir simulation model was set up to history match experimental production and pressure data to obtain multi-phase flow functions. Two experiments were conducted on Minnelusa formation (eolian sand) rock samples at 93°C with TC crude oil and synthetic brines. Placement of an oil-wet membrane on one plug end and a water-wet disk on the other end guaranteed that only one phase was able to flow through each sample end at any given time. In one experiment, a 57,491ppm-brine (High-Salinity) was used during the imbibition process, while a 20-fold dilution of the High-Salinity brine (Low-Salinity) was used in the other experiment. Correspondingly, two unsteady-state experiments at fixed injection rate were completed on Minnelusa formation rock samples placed in the coreflooding system using comparable experimental conditions as those in the capillary pressure experiments. Comparison of high- and low-salinity experimental results shows that more noticeable capillary hysteresis toward water-wetness arose in the low-salinity experiment. High-salinity experiment results showed that the imbibition resistivity index was higher than that corresponding to drainage. History matching of the transient production data in capillary pressure experiments along with end-points obtained from unsteady-state core flooding experiments was used to obtain relative permeability curves. Availability of high-quality capillary pressure data at reservoir conditions improved the accuracy of relative permeability curves obtained from history matching unsteady-state core flooding experiments. Our results show a substantial improvement in obtaining both capillary pressure and relative permeability curves at reservoir conditions resulting from a combination of steady- and unsteady-state experiments. Capillary pressure results confirm that hysteresis is more prominent under low-salinity conditions and apparent higher oil trapping is observed during imbibition, compared to high-salinity conditions. Unsteady-state coreflooding results also show that low-salinity brine is not conducive to enhanced oil recovery in low-salinity waterflooding. Geochemical effects appear to negatively impact beneficial interfacial mechanisms proposed to benefit oil recovery such as the formation of more viscoelastic interfaces under low-salinity conditions. We conclude that coupling of fluid–fluid and rock–fluid interactions, including geochemical reactions, needs to be accounted for to better explain low-salinity waterflooding mechanisms.

Co-sequestration of SO2 with supercritical CO2 in carbonates: An experimental study of capillary trapping, relative permeability, and capillary pressure

In this study we performed three categories of steady- and unsteady-state core-flooding experiments to investigate capillary trapping, relative permeability, and capillary pressure, in a scCO2+SO2/brine/limestone system at elevated temperature and pressure conditions, i.e., 60°C and 19.16MPa. We used a Madison limestone core sample acquired from the Rock Springs Uplift in southwest Wyoming. We carried out two sets of steady-state drainage-imbibition relative permeability experiments with different initial brine saturations to study hysteresis. We found that the final scCO2+SO2 drainage relative permeability was very low, i.e., 0.04. We also observed a rapid reduction in the scCO2-rich phase imbibition relative permeability curve, which resulted in a high residual trapping. The results showed that between 62.8% and more than 76% of the initial scCO2+SO2 at the end of drainage was trapped by capillary trapping mechanism (trapping efficiency). We found that at higher initial brine saturations, the trapping efficiency was higher. The maximum initial and residual scCO2-rich phase saturations at the end of primary drainage and imbibition were 0.525 and 0.329, respectively. Each drainage-imbibition cycle was followed by a dissolution process to re-establish Sw=1. The dissolution brine relative permeabilities for both cycles were also obtained. We characterized the scCO2+SO2/brine capillary pressure hysteresis behavior through unsteady-state primary drainage, imbibition, and secondary drainage experiments. We observed negative imbibition capillary pressure curve indicative of possible wettability alteration throughout the experiments due to contact with scCO2+SO2/brine fluid system. The trapping results were compared to those reported in literature for other carbonate core samples. We noticed slightly more residual trapping in our sample, which might be attributed to heterogeneity, different viscosity ratio, and pore-space topologies. The impact of dynamic effects, i.e., high brine flow rate imbibition tests, on trapping of the scCO2-rich phase was also explored. We performed two imbibition experiments with relatively high brine flow rates. The residual scCO2 saturation dropped to 0.291 and 0.262 at the end of the first and second imbibition tests, i.e., 11.5% and 20.4%, respectively, compared to 0.329 under capillary-dominated regime.

An Approach for the Estimation of Dynamic Imbibition Capillary Pressure Curves

Capillary pressure is one of the most important parameters for reservoir engineering studies. Although different experimental methods are devised to measure capillary pressure, these methods do not represent the physics of fluid flow, which happens at reservoir conditions. Thus, it is attempted to extract the capillary pressure from spontaneous imbibition data, the common mechanism of oil production in water wet porous media. In this work, a new approach is developed to obtain the imbibition capillary pressure curve by using spontaneous water imbibition data in oil-water-rock systems. Comparison of calculated imbibition capillary pressure curves by the new approach with experimental values shows a good accordance with each other.

The Impact of Tides on the Capillary Transition Zone

The capillary transition zone, also known as the capillary fringe, is a zone where water saturations decrease with height above the water table/oil–water contact as a result of capillary action. In some oil reservoirs, this zone may contain a significant proportion of the oil in place. In groundwater assessments, the capillary fringe can profoundly affect contaminant transport. In this study, we investigated the influence of a tidally induced, semi-diurnal, change in water table depth on the water saturation distribution in the capillary fringe/transition zone. The investigation used a mixture of laboratory experiments, in which the change in saturation with depth was monitored over a period of 90 days, and numerical simulation. We show that tidal changes in water table depth can significantly alter the vertical water saturation profile from what would be predicted using capillary–gravity equilibrium and the drainage or imbibition capillary pressure curves.

A Dimensionless Capillary Pressure Function for Imbibition Derived From Pore-Scale Modeling in Mixed-Wet-Rock Images

Summary It has been demonstrated experimentally that Leverett's J-function yields almost unique dimensionless drainage capillary pressure curves in relatively homogeneous rocks at strongly water-wet conditions, whereas for imbibition at mixed-wet conditions, it does not work satisfactorily because the permeability dependency on capillary pressure has been reported to be weak. The purpose of this study is to formulate a new dimensionless capillary pressure function for mixed-wet conditions on the basis of pore-scale modeling, which could overcome these restrictions. We simulate drainage, wettability alteration, and imbibition in 2D rock images by use of a semianalytical pore-scale model that represents the identified pore spaces as cross sections of straight capillary tubes. The fluid configurations occurring during drainage and imbibition in the highly irregular pore spaces are modeled at any capillary pressure and wetting condition by combining the free-energy minimization with an arc meniscus (AM)-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Capillary pressure curves for imbibition are simulated for different mixed-wet conditions in Bentheim sandstone samples, and the results are scaled by a newly proposed improved J-function that accounts for differences in formation wettability induced by different initial water saturations after primary drainage. At the end of primary drainage, oil-wet-pore wall segments are connected by many water-wet corners and constrictions that remain occupied by water. The novel dimensionless capillary pressure expression accounts for these conditions by introducing an effective contact angle that depends on the initial water saturation and is related to the wetting property measured at the core scale by means of a wettability index. The accuracy of the proposed J-function is tested on 36 imbibition capillary pressure curves for different mixed-wet conditions that are simulated with the semianalytical model in scanning-electron-microscope (SEM) images of Bentheim sandstone. The simulated imbibition capillary pressure curves and the reproduced curves, based on the proposed J-function, are in good agreement for the mixed-wet conditions considered in this study. The detailed behavior is explained by analyzing the fluid displacements occurring in the pore spaces. It is demonstrated that the proposed J-function could be applied to mixed-wet conditions to generate a family of curves describing different wetting states induced by assigning different wetting properties on the solid surfaces or by varying the initial water saturation after primary drainage. The variability of formation wettability and permeability could be described more accurately in reservoir-simulation models by means of the proposed J-function, and hence the opportunity arises for improved evaluation of core-sample laboratory experiments and reservoir performance.

Capillary pressures in carbon paper gas diffusion layers having hydrophilic and hydrophobic pores

Capillary pressures in a carbon paper gas diffusion layer (GDL) having hydrophilic and hydrophobic pores of a polymer electrolyte membrane fuel cell (PEMFC) are investigated by both lattice Boltzmann simulations and experimental measurements. The simulated and measured capillary pressures as a function of water saturation for water drainage and imbibition processes in the GDL are presented and compared. It is shown that the pore-scale simulated drainage and imbibition capillary pressure curves are in good agreement with that obtained by experiment, both indicating the coexistence of hydrophilic and hydrophobic properties in the polytetrafluoroethylene (PTFE) treated carbon paper GDLs. The fitted capillary pressure curves, obtained from this paper, can provide more accurate predictions of the capillary pressure in carbon paper GDLs with non-uniform porosity and wettability than the standard Leverett–Udell relationship which was obtained for soil with more uniform porosity and wettability.

Estimation of Imbibition Capillary Pressure Curves from Spontaneous Imbibition Data

A closed-form solution for calculating imbibition capillary pressure from experimental data has been derived on the basis of the assumption of a constant capillary diffusion coefficient combined with Corey functions for the relative permeability curves. The solution is almost similar to the capillary pressure correlation reported by Skjaeveland et al. (Skjaeveland, S. M., Siqveland, L. M., Kjosavik, A., Hammervold Thomas, W. L. and Virnovsky, G. SPE Reservoir Eval. Eng. 2000, 3 (1), 60−67), but it allows for calculation of the empirical fit parameters from experimental data. Calculated imbibition capillary pressure curves show the correct qualitative behavior because of variations in the curvature of the relative permeability curves, the end-point values on the relative permeability curves, the absolute permeability, and the capillary diffusion coefficient. Capillary pressure threshold values calculated from the model are in accordance with experimental data, assuming reasonable input data. The model, how...

History Matching for Determination of Fracture Permeability and Capillary Pressure

Summary For naturally fractured reservoirs, it is very difficult to quantify future prediction without proper fracture properties, including such factors as fracture permeability, fracture orientation, and fracture length, and capillary pressure. Capillary pressure and fracture permeability can interact in a way that can produce nonunique results. Evaluation of core data may provide us with some information about imbibition capillary pressure curves; however, quantification of fracture permeability is determined largely by matching production data. This paper presents an integrated approach to history matching naturally fractured reservoirs by adjusting the fracture permeability of individual fractures and water/oil capillary pressure curves. This paper is focused mainly on history-matching procedure and not on geological-model construction. By minimizing an objective function to history matching production data, we generate estimates of fracture permeability of individual fractures and water/oil capillary pressure curves. All implementations were incorporated into a commercial simulator and iterated in the automatic-history-matching scheme. The adjoint method and an efficient direct solver were used to reduce CPU time for calculating the sensitivity-coefficient matrix. A 2D synthetic case was used, with the fracture distribution from a Middle East reservoir, to validate this method.

Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs

Summary An oil/water capillary transition zone often contains a sizable portion of a field's initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Sor) against depth, and on the rock and fluid interactions that control the residual oil saturation (Sor), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones.

Influence of wettability on petrophysical properties during imbibition in a random dense packing of equal spheres

Wettability, defined in terms of the value of contact angle of wetting–nonwetting–solid phase interface, is an important feature governing flow and transport processes in porous media. In this work we investigate the influence of wettability on the capillary pressure vs. saturation curve and on relative permeability during imbibition. To describe imbibition, we propose a new way of modeling it, based upon a physically consistent dynamic criterion for the imbibition of an individual pore, originally suggested by Melrose. We illustrate this approach in a simple but physically representative porous medium, the “ideal soil” (a dense random packing of equal spheres). Complete knowledge of the pore space geometry allows making a priori predictions of pore-level processes, without invoking adjustable parameters. This approach allows modeling imbibition for different values of contact angle and different initial conditions (as different drainage endpoints). The simulation yields the pore-level configuration of both fluid phases at each value of saturation. Relative permeabilities are calculated by simulating steady flow through the pore space occupied by each phase. The geometric and topological features of the flow network are directly connected to the geometry of the model rock and distribution of liquid phases in it. The simulated imbibition capillary pressure curves and relative permeability to the wetting phase are very sensitive to the value of contact angle in the whole range of wetting phase saturation. At the same time, relative permeability to the non-wetting phase is not much influenced by the wettability. Predicted capillary pressures and relative permeabilities compare favorably with experimental data for a range of wettabilities, providing strong support for the dynamic imbibition criterion.

Determination of the effective transport coefficients of pore networks from transient immiscible and miscible displacement experiments

Transient immiscible and miscible displacement experiments performed on artificial glass‐etched pore networks are used to determine the capillary and relative permeability curves as well as the hydrodynamic dispersion coefficients. The transient responses of the total and axial distribution of the wetting phase (WP) saturation and the pressure drop across the pore network are introduced into an inverse modeling scheme to estimate the imbibition capillary pressure and relative permeability curves of pore networks by varying the capillary number, the contact angle, and the shear‐thinning rheology of the nonwetting phase (NWP). The temporal evolution of the spatial distribution of the solute concentration profiles over selected areas of the pore network is fitted to analytical one‐dimensional solute dispersion models to estimate the longitudinal dispersion coefficient as a function of the Peclet number, in single‐ and dual‐pore networks. Under an unfavorable viscosity ratio the growth pattern is a two‐dimensional fractal object, its description with the one‐dimensional macroscopic two‐phase flow equations is questionable, a high uncertainty is introduced into the capillary pressure curve, whereas “average” relative permeability functions are estimated. The relative permeability of the NWP may be a decreasing or increasing function of the capillary number over the viscous or capillary fingering pattern, respectively. The relative permeability of the WP is an increasing function of the capillary number and increases weakly with the NWP shear‐thinning rheology strengthening. The longitudinal dispersion coefficient varies nonlinearly with Peclet number following power laws with exponents ranging from 1 to 2 and depending on the relative contribution fraction of the macrodispersion (associated with the spatial variation of pore sizes) and Taylor dispersion (associated with the flow channeling) to the entire process.

The representation of two phase fault-rock properties in flow simulation models

Faults are represented conventionally in production flow simulation models using transmissibility multipliers which capture the single phase, but not the two phase, fault-rock properties. Available data indicate that fault-rocks have similar two phase properties to sediments of the same permeability, hence existing methods can be applied to estimate two phase fault-rock properties from their intrinsic permeabilities. Two methods of representing the two phase fault-rock properties implicitly in the flow simulator are compared, using one-dimensional numerical flow models containing water-wet faults with imbibition capillary pressure curves. The method which is the closer two phase analogue of the single phase transmissibility multiplier is inappropriate, as the implementation is unreasonably unwieldy. A simpler implementation is to derive pseudo-relative permeability functions including the fault-rock properties in the upstream grid block; these properties are then incorporated directly in the simulator. Relative transmissibility multiplier functions can be back-calculated from the pseudo-relative permeability functions, and indicate how closely the single phase multiplier approximates two phase flow through the fault. Implementation in a 3D model with complex fault juxtapositions validates the approach, and a practical workflow for the routine inclusion of two phase fault-rock properties in conventional faulted flow simulation models is outlined.

Effects of heterogeneities on capillary pressure–saturation–relative permeability relationships

In theories of multiphase flow through porous media, capillary pressure–saturation and relative permeability–saturation curves are assumed to be intrinsic properties of the medium. Moreover, relative permeability is assumed to be a scalar property. However, numerous theoretical and experimental works have shown that these basic assumptions may not be valid. For example, relative permeability is known to be affected by the flow velocity (or pressure gradient) at which the measurements are carried out. In this article, it is suggested that the nonuniqueness of capillary pressure–relative permeability–saturation relationships is due to the presence of microheterogeneities within a laboratory sample. In order to investigate this hypothesis, a large number of “numerical experiments” are carried out. A numerical multiphase flow model is used to simulate the procedures that are commonly used in the laboratory for the measurement of capillary pressure and relative permeability curves. The dimensions of the simulation domain are similar to those of a typical laboratory sample (a few centimeters in each direction). Various combinations of boundary conditions and soil heterogeneity are simulated and average capillary pressure, saturation, and relative permeability for the “soil sample” are obtained. It is found that the irreducible water saturation is a function of the capillary number; the smaller the capillary number, the larger the irreducible water saturation. Both drainage and imbibition capillary pressure curves are found to be strongly affected by heterogeneities and boundary conditions. Relative permeability is also found to be affected by the boundary conditions; this is especially true about the nonaqueous phase permeability. Our results reveal that there is much need for laboratory experiments aimed at investigating the interplay of boundary conditions and microheterogeneities and their effect on capillary pressure and relative permeability.

Intermediate wettability by chemical treatment

To study the effect of wettability on recovery, we used a chemical additive that changes the surface properties of natural rock samples while keeping interfacial tension and viscosity constant. The wettability change is weaker than for other chemical treatments (e.g., silane) and is therefore closer to reservoir cases. The chemical additive is a potassium methyl siliconate that is soluble in water. A polymerization of the adsorbed layer on the pore surface is obtained when the pH is lowered near neutral. Outcrop sandstone samples were treated either with or without the presence of oil (at Swirr) using carbon dioxide as a neutralizer. Efficiency of the treatment is determined mainly by comparing centrifuge (negative) imbibition capillary pressure curve on treated and untreated samples. Micropore membrane technique was also applied to measure the positive imbibition capillary pressure curve. The main results are (1) the final oil saturation (Sor) is reduced from 0.4 to 0.3 and 0.1 depending on how the treatment was performed; (2) there are only minor modifications on the primary drainage capillary pressure curve; and (3) water relative permeability at Sor measured after centrifuge forced imbibition is not modified by the treatment.

Characterization of Wettability From Spontaneous Imbibition Measurements

Abstract Of the many methods of characterizing wettability of a porous medium, the most commonly used are the Amott test and the USBM test. The Amott test does not discriminate adequately between systems that give high values of wettability index to water and are collectively described as very strongly water-wet. The USBM test does not recognize systems which achieve residual oil saturation by spontaneous imbibition. For these conditions the measurement of imbibitions rate provides a useful characterization of wettability. Methods of interpreting spontaneous imbibition data are reviewed and a new method of quantifying wettability from rate of imbibition is proposed. Capillary pressure is the driving force in spontaneous imbibition. The area under an imbibition curve is related to the work of displacement that results from a decrease in surface free energy. Imbibition rate data can thus be compensated for differences in interfacial tension, viscosity, pore structure, and sample size. Wettability, the remaining key factor in determining the capillary driving force and the related imbibition rate, can be used to plot the difference in saturation as a function of time. These data are then used to obtain pseudo imbibition capillary pressure curves and a wettability index based on the relative areas under these curves is defined as the relative pseudo work of imbibition. The method is applied to two crude oil/brine/rock systems. The method is compared with the Amott wettability index for different wettability states in cores with crude oil. Correlations of wettability indices with waterflood recoveries are presented. Introduction Reservoir wettability is a critical parameter in many types of oil recovery processes. Recovery of oil by spontaneous imbibition of water into the matrix of fractured reservoirs is a frequently cited example. Many methods of characterizing wettability have been proposed. The Amott test(1) and USBM test(2) are the most commonly used methods of characterizing wettability of oil/brine/rock systems. Both tests depend on capillary pressure and microscopic displacement efficiency. In application of either test, it is common to first displace water by oil to reach an initial water saturation, Swi. This step in the test is important because the wettability index, in addition to core treatment such as aging time and temperature, is strongly dependent on the value of the initial water saturation(3). The next step is to immerse the sample in water and measure the oil recovered by spontaneous imbibition. The corresponding increase in water saturation is ΔSws. In the Amott test, the sample is then subjected to what is known as forced displacement either by centrifuging, as originally proposed by Amott(1), or by waterflooding(4). If the increase in water saturation by forced displacement is ΔSwf, the Amott wettability index to water, Iw, is then defined as Equation 1 (available in full paper) If nearly all of the oil recovery occurs by spontaneous imbibition, Iw is close to 1.0 and the system is described as very strongly water-wet. Systems are increasingly less water-wet as for smaller values of Iw.