Irreducible Wetting Phase Saturation Research Articles

Investigation on the influence of capillary number on drainage in porous media using a lattice Boltzmann method

This work investigates the effect of the capillary number on the saturation of wetting and nonwetting phases during processes of drainage. A multicomponent Lattice Boltzmann model with a two-relaxation time scheme is used to simulate the flow in 2D and 3D digital models of porous rocks. The capillary number is varied by setting different values of the fluid inlet velocity, while viscosity and interfacial tension are fixed. The results show the invasion of nonwetting phase in the narrow pores of the media, forcing the wetting fluid to leave through the outlet. Different patterns are observed depending on the capillary number and the degree of porosity and heterogeneity of the models. Several pore-scale events are observed and play an important role in the trapping of wetting fluid. The nonwetting phase saturation is measured at breakthrough and quasi-steady states. In 2D models, the effect of the low velocity of the fluid at low Ca provides a better condition for fluid redistribution, causing a higher nonwetting fluid saturation. In 3D models, a lower value of Ca leads to more trapped wetting fluid mainly because of the media geometries. In all cases, the highest Ca range resulted in the highest nonwetting fluid saturation at a quasi-steady state. The saturation and relative permeability curves at the point of irreducible wetting phase saturation show that the degree of heterogeneity in 3D models has an important effect on sweeping effectiveness, which seems to be more significant than porosity or intrinsic permeability of the models.

A general capillary equilibrium model to describe drainage experiments in heterogeneous laboratory rock cores

Macroscopic observations of two-phase flow in porous rocks are largely affected by the heterogeneity in continuum properties at length scales smaller than a typical laboratory sample. The ability to discriminate among the rock properties at the origin of the heterogeneity is key to the development of numerical models to be used for prediction. Here, we present a capillary equilibrium model that represents spatial heterogeneity in dual-porosity porous media in terms of the capillary entry pressure, 1/α, and the irreducible wetting phase saturation, Sir. Both parameters are used to scale local capillary pressure curves by using three-dimensional imagery acquired during multi-rate gas/liquid drainage displacements. We verify the proposed approach by considering the case study of a dual-porosity limestone core and use the spatial variation in Sir as proxy for microporosity heterogeneity. The latter places potentially next-to-leading order controls on the observed fluid saturation distribution, which is strongly correlated to the distribution of 1/α. While microporosity is by and large uniform at the observation scale on the order of 0.1 cm3, the spatial correlation of 1/α is on the order of 1 cm and is therefore not statistically represented in the volume of typical laboratory core samples.

New fractal-dimension-based relation model for estimating absolute permeability through capillary pressure curves

This paper developed a new general power-law relation model to predict absolute permeability, which innovatively integrating Poiseuille's law and fractal capillary pressure model. The proposed model took into account the assumption of Poiseuille's law and Purcell theory characterizing the porous media as capillary tubes of various radii. Kewen Li fractal capillary pressure model was preferred to characterize capillary pressure curves and derive the new permeability relation model due to its higher fitting accuracy compared with Brooks-Corey model. Further, a randomly collected dataset containing 151 rock samples was used to calibrate the coefficients and another 53 rock samples were used to validate the feasibility of this new model. The proposed permeability model can predict absolute permeability through 5 basic parameters as follows: porosity, displacement pressure, capillary pressure at irreducible wetting phase saturation, irreducible wetting phase saturation and the fractal dimension. The fractal dimension, an indicator of the porous media heterogeneity, has a great impact on flow capacity in natural rock system. For rock samples with fractal dimension Df > 3, the capillary pressure matching results of Kewen Li power-law model are much better than those of Brooks-Corey capillary pressure model. 151 mercury injection capillary pressure (MICP) curves were all well fitted by Kewen Li model to estimate the basic parameters, and the absolute permeability of these rock samples were predicted through the new relation model. Then this study performed a comparison between the measured permeability in laboratory and calculated permeability through the new relation model. The regression Coefficient of Determination (R2) for measured and calculated permeability of 151 rock samples was 0.967. Besides, the new model consistently obtained attractive prediction results for another 53 validation rock samples. The new relation model can be widely used to estimate the absolute permeability for various rock types, including limestone, sandstone, dolomite, and from tight rocks to high permeability rocks.

Consecutive Experimental Determination of Stress‐Dependent Fluid Flow Properties of Berea Sandstone and Implications for Two‐Phase Flow Modeling

AbstractIn this study, changes in the hydrodynamic properties of Berea sandstone at a constant temperature of 40 °C are reported as effective confining stress is increased to 30 MPa. Through a novel consecutive approach, porosity, absolute permeability, drainage relative permeability, and drainage capillary pressure were shown to systematically change with effective stress. The relative permeability measurements were taken using a steady‐state method for the N2/water fluid pair. A second method, in which a saturated core with the wetting phase was flushed with the non‐wetting phase at an increasing flow rate, was used to determine the drainage capillary pressure. Core saturation was determined using a gas separation unit and mass‐balance considerations. This study revealed a decrease in porosity and absolute permeability, from 13.16% and 58 mD to 12.24% and 36 mD, respectively, with the increase in effective confining stress. In terms of relative permeability curves, this study showed a systematic decrease in irreducible wetting phase saturation from 0.44 to 0.24 as effective stress increased; this could be interpreted in core‐scale as a progressive tendency of the initially water‐wet Berea sandstone to the gas phase. The capillary pressure curve also presented an upward shift in response to increased effective stress. These changes in the hydrodynamic rock properties with stress suggest that scaling flow parameters of porous media under effective stress conditions may be required to accurately predict flow behavior under conditions of changing stress.

On the consistency of scale among experiments, theory, and simulation

Abstract. As a tool for addressing problems of scale, we consider an evolving approach known as the thermodynamically constrained averaging theory (TCAT), which has broad applicability to hydrology. We consider the case of modeling of two-fluid-phase flow in porous media, and we focus on issues of scale as they relate to various measures of pressure, capillary pressure, and state equations needed to produce solvable models. We apply TCAT to perform physics-based data assimilation to understand how the internal behavior influences the macroscale state of two-fluid porous medium systems. A microfluidic experimental method and a lattice Boltzmann simulation method are used to examine a key deficiency associated with standard approaches. In a hydrologic process such as evaporation, the water content will ultimately be reduced below the irreducible wetting-phase saturation determined from experiments. This is problematic since the derived closure relationships cannot predict the associated capillary pressures for these states. We demonstrate that the irreducible wetting-phase saturation is an artifact of the experimental design, caused by the fact that the boundary pressure difference does not approximate the true capillary pressure. Using averaging methods, we compute the true capillary pressure for fluid configurations at and below the irreducible wetting-phase saturation. Results of our analysis include a state function for the capillary pressure expressed as a function of fluid saturation and interfacial area.

Wettability Effects on Capillary Pressure, Relative Permeability, and Irredcucible Saturation Using Porous Plate

An understanding of the mechanisms by which oil is displaced from porous media requires the knowledge of the role of wettability and capillary forces in the displacement process. The determination of representative capillary pressure (Pc) data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation. Initial water-wet reservoir core samples with porosities ranging from 23 to 33%, absolute air permeability of 50 to 233 md, and initial brine saturation of 63 to 87% were first tested as water-wet samples under air-brine system. This yielded irreducible wetting phase saturation of 19 to 21%. The samples were later tested after modifying their wettability to oil-wet using a surfactant obtained from glycerophtalic paint; and the results yielded irreducible wetting phase saturation of 25 to 34%. From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase.

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.

A new universal permeability model derived from mercury capillary pressure data

This paper presents the construction and verification of a new better semi-analytical, statistically derived universal model than that modified from Huet and Blasingame equation for estimating absolute permeability from mercury injection capillary pressure data. The foundation of my new model is the petrophysical relation between absolute permeability and capillary pressure/wetting phase saturation properties. I also incorporate the characteristics of capillary pressure behavior using the classic Brooks-Corey power-law model. The final form of my new proposed model allows us to predict absolute permeability as a function of effective porosity, irreducible wetting phase saturation, displacement or threshold pressure corresponding pore-throat radius, and basic pore size characteristics. I built my model using 189 sets of mercury-injection (Hg-air) capillary pressure data and measured permeability including core samples from several reservoirs both carbonate and sandstone lithologies. I identified this correlation by quantifying its accuracy and precision based on regression analysis. I compare permeability estimates obtained from Huet and Blasingame mercury-injection capillary pressure-based model and my new universal predicted permeability model to a set of laboratory measured permeability of my studied core sample and previously published data results, respectively, where I quantifying the method's accuracy and precision based on error analysis. The measured permeability samples range is from 0.003 to 5,341 md. I review current employed models that are classified as belonging to Poiseuille model.

Using Capillary Pressure Derived Parameters for Improving Permeability Prediction

This paper presents the construction and verification of a new better semi-analytical, statistically derived universal model than that modified from Huet and Blasingame equation for estimating absolute permeability from mercury injection capillary pressure data. The foundation of my new model is the petrophysical relation between absolute permeability and capillary-pressure/wetting phase saturation properties. I also incorporate characteristics of capillary pressure behavior using the classic Brooks-Corey power-law model. The final form of my new proposed model allowed us to predict absolute permeability as a function of effective porosity, irreducible wetting phase saturation, displacement or threshold pressure corresponding pore throat radius, and basic pore size characteristics. I built my model using 189 sets of mercury—injection (Hg-air) capillary pressure data and measured permeability-including core samples from several reservoirs both carbonate and sandstone lithologies. I identified this correlation by quantifying its accuracy and precision based on regression analysis. I compared permeability estimates obtained from Huet and Blasingame mercury-injection capillary-pressure-based model and my new universal predicted permeability model to a set of laboratory measured permeability of my studied core sample and previously published data results respectively, where I quantified the method’s accuracy and precision based on error analysis. The measured permeability samples range is from 0.003 mD to 5341 mD. I review current employed models that are classified as belonging to Poiseuille model.

Classifying rock lithofacies using petrophysical data

This study automates a type-curve technique for estimating the rock pore-geometric factor (λ) from capillary pressure measurements. The pore-geometric factor is determined by matching the actual rock capillary pressure versus wetting-phase saturation (Pc–Sw) profile with that obtained from the Brooks and Corey model (1966 J. Irrigation Drainage Proc. Am. Soc. Civ. Eng. 61–88). The pore-geometric factor values are validated by comparing the actual measured rock permeability to the permeability values estimated using the Wyllie and Gardner model (1958 World Oil (April issue) 210–28). Petrophysical data for both carbonate and sandstone rocks, along with the pore-geometric factor derived from the type-curve matching, are used in a discriminant analysis for the purpose of developing a model for rock typing. The petrophysical parameters include rock porosity (), irreducible water saturation (Swi), permeability (k), the threshold capillary-entry-pressure (Pd), a pore-shape factor (β), and a flow-impedance parameter (n) which is a property that reflects the flow impedance caused by the irreducible wetting-phase saturation. The results of the discriminant analysis indicate that five of the parameters (, k, Pd, λ and n) are sufficient for classifying rocks according to two broad lithology classes: sandstones and carbonates. The analysis reveals the existence of a significant discriminant function that is mostly sensitive to the pore-geometric factor values (λ). A discriminant-analysis classification model that honours both static and dynamic petrophysical rock properties is, therefore, introduced. When tested on two distinct data sets, the discriminant-analysis model was able to predict the correct lithofacies for approximately 95% of the tested samples. A comprehensive database of the experimentally collected petrophysical properties of 215 carbonate and sandstone rocks is provided with this study.

Analytical derivation of Brooks–Corey type capillary pressure models using fractal geometry and evaluation of rock heterogeneity

The Brooks–Corey type capillary pressure models (three models on the relationship between capillary pressure and saturation) were derived theoretically from fractal modeling of porous media. The pore size distribution index is coupled with fractal dimension. The pore size distribution index increases with the decrease in fractal dimension. Capillary pressure curves of different rock samples were measured using a mercury intrusion technique. The values of fractal dimension were calculated using three fractal models and the results were compared. The heterogeneity of rock was evaluated using fractal dimension. The consistency between fractal dimension and the frequency graph of pore size distribution was examined. The theoretical derivation demonstrated that the three fractal models are correlated. Sensitivity analysis data showed that the accuracy in estimating irreducible wetting-phase saturation is essential to obtain the power-law relationship between the capillary pressure and the normalized wetting-phase saturation.

Infinite-Acting Physically Representative Networks for Capillarity-Controlled Displacements

Summary Drainage/imbibition simulations are traditionally performed on finite regular lattices. If physically representative networks are used instead, the spatial correlation of pore space features inherent in granular materials is automatically accounted for. However, even these networks are obtained from finite samples, and conditions must be specified on the boundaries. Making the conditions correspond to physically realistic situations is difficult, especially for simulations of phase trapping. This paper presents a method of constructing infinite-acting model rocks, in which a well-defined criterion for phase trapping is possible that is independent of boundary conditions. The foundation of the model is computergenerated dense random periodic packings of spheres. We illustrate the method with simulations of drainage and irreducible wetting-phase saturations. To eliminate possible confounding effects from grains being arranged differently, we compare simulations in infinite-acting networks with simulations in the finite network taken from the unit cell of the periodic packing. Wetting-phase connectivity is assessed globally and accounts for all phase morphologies, including pendular rings. The drainage endpoint for a finite network was highly sensitive to the number and location of the exit pores; while using the infinite-acting network, we removed this latter sensitivity. Comparison with experiments showed that a strict criterion of wetting-phase connectivity (pores connected only by throats filled with wetting phase) cannot account for typical values of Sw,irr and that connectivity must persist via pendular rings. Typical laboratory experiments and simulations in finite networks yield drainage curves that approach irreducible wetting phase saturation Sw,irr gradually, with large changes in capillary pressure inducing only small changes in saturation. Simulations in infinite-acting networks do not exhibit this behavior. We argue that these simulations are more representative of behavior in the field and that typical laboratory measurements underestimate the value of Sw,irr.

A multi-flowpath model for the interpretation of immiscible displacement experiments in heterogeneous soil columns

This work focuses on the phenomenon of the immiscible two-phase flow of water and oil in saturated heterogeneous soil columns. The goal is to develop a fast and reliable method for quantifying soil heterogeneities for incorporation into the relevant capillary pressure and relative permeability functions. Such data are commonly used as input data in simulators of contaminant transport in the subsurface. Rate-controlled drainage experiments are performed on undisturbed soil columns and the transient response of the axial distribution of water saturation is determined from electrical measurements. The transient responses of the axial distribution of water saturation and total pressure drop are fitted with the multi-flowpath model (MFPM) where the pore space is regarded as a system of parallel paths of different permeability. The MFPM enables us to quantify soil heterogeneity at two scales: the micro-scale parameters describe on average the effects of pore network heterogeneities on the two-phase flow pattern; the macro-scale parameters indicate the variability of permeability at the scale of interconnected pore networks. The capillary pressure curve is consistent with that measured with mercury intrusion porosimetry over the low pressure range. The oil relative permeability increases sharply at a very low oil saturation (< 10 − 3 ) and tends to a high end value. The water relative permeability decreases abruptly at a low oil saturation (~ 0.1), whereas the irreducible wetting phase saturation is quite high. The foregoing characteristics of the two-phase flow properties are associated with critical (preferential) flowpaths that comprise a very small percentage of the total pore volume, control the overall hydraulic conductivity, and are consistent with the very broad range of pore-length scales usually probed in soil porous matrix.

The effect of micro-heterogeneity and capillary number on capillary pressure and relative permeability curves of soils

The determination of the two-phase flow coefficients (such as the capillary pressure, P c, and relative permeabilities, k rw, k ro) is of a key importance to model the two-phase flow processes taking place during contaminant transport in subsurface. In the present work, transient immiscible displacement experiments are performed at various flow rates on long disturbed soil columns. The capillary pressure–saturation-relative permeability relationships of soils characterized by narrow and broad grain size distributions are estimated with inverse modeling from rate-controlled displacement experiments and are correlated with the grain size variability and ratio of viscous to capillary forces (capillary number). A soil core holder assembled with electrodes is constructed to monitor the axial distribution of water saturation. A new technique is developed to determine the water saturation averaged over successive segments of the soil column by measuring the transient responses of the electrical resistance between vertical ring electrodes. The transient responses of the average oil (water) saturation in five segments along with the total pressure drop across the soil column are introduced into an inverse modeling numerical solver of the macroscopic two-phase flow equations to estimate simultaneously the capillary pressure and relative permeability curves under dynamic conditions. The water and oil relative permeabilities increase drastically with the capillary number, while the capillary pressure curve of soils with broad grain (pore) size distribution is wider than that of soils with narrow grain (pore) size distribution. For soils with high variability of grain sizes, the irreducible wetting phase saturation is higher, the relative permeability curves are sharper and the end oil relative permeability is higher compared to soils with low variability of grain sizes.

Forced imbibition in natural porous media: Comparison between experiments and continuum models

A well-characterized set of large-scale laboratory experiments is presented, illustrating forced imbibition displacements in the presence of irreducible wetting phase saturation in a cylindrical, homogeneous Berea sandstone rock. Experiments are designed to operate in the regime of compact microscopic flows and large-scale viscous instability. The distribution of fluid phases during the flow process is visualized by high-resolution computed tomography imaging. Linear stability analysis and high-accuracy numerical simulations are employed to analyze the ability of macroscopic continuum equations to provide a consistent approximation of the displacement process. The validity of the equilibrium relative permeability functions, which form the basis for the continuum model, is fundamentally related to the stability of the displacement process. It is shown that not only is the stable flow regime modeled accurately by existing continuum models, but the onset of instability as well as the initial unstable modes are also determined with reasonable accuracy for unstable flows. However, the continuum model is found to be deficient in the case of fully developed unstable flows.

Non-uniqueness in capillary pressure–saturation–relative permeability relationships for two-phase flow in porous media: Interplay between intensity and distribution of random micro-heterogeneities

The two-phase flow behaviour in porous media is determined on the basis of capillary pressure–saturation–relative permeability relationships ( P c – S – K r ). These relationships are highly non-linear and obtained by laboratory experiments on porous samples, typically around 10–12 cm in length. It is normally assumed that these samples are homogeneous; however it is well-known that this is in fact not the case and that even at this scale micro-scale heterogeneities exist. Two-phase flow experiments on soils with different properties (e.g., particle and pore size distribution, permeabilities, etc) result in different P c – S – K r relationships implying that they cause non-uniqueness in these curves. Recent work has shown that the presence of the micro-heterogeneities has a significant effect on the measured P c – S – K r relationships and they cause non-uniqueness in these relationships. In the previous work in this area, the micro-heterogeneity effects on the P c – S – K r relationships have been analysed in a number of contexts, e.g., uniformly distributed heterogeneities (simplified cases), various binary sand combinations, hydraulic parameters (e.g., entry pressure, permeability), boundary conditions, etc. There is also some evidence that the intensity and distribution of the micro-heterogeneities affect the P c – S – K r relationships. In the present work we use numerical simulations to investigate further the nature of these effects, in particular how the interplay between the intensity and random distribution of micro-heterogeneities affect the P c – S – K r relationships. Seven randomly heterogeneous patterns have been defined. These domains represent coarse sand media with fine sand blocks embedded in them. The domain size ( 12 cm × 12 cm ) has been chosen so that it represents a typical laboratory scale device. The results of the simulations show that it is particularly important to take into account both the intensity and distribution of heterogeneity when determining the effective P c – S – K r relationships of a sample. Further, there is a complex interplay between the intensity and distribution of micro-scale heterogeneities which determines the P c – S – K r curves. This observation is in contrast to the results of domains with uniformly distributed heterogeneities. We have found that in general if the intensity of heterogeneity is high; the irreducible wetting phase saturation ( S iw ) of the sample is also high. The direction of flow and the orientation of the samples also have significant effects. For example, the injection of an immiscible phase from the top (vertically downward) of water saturated porous domain leads to a lower S iw than injecting on horizontal plane. On the other hand, injection from the bottom (vertically upwards) leads to a higher S iw . As expected, the distribution of heterogeneity has a significant effect on the saturation distribution and the shape of the P c – S – K r curves. However, we show that if the heterogeneities are distributed in such a way that they are closer to the boundary of injection, the irreducible wetting phase saturation is higher.

A Modified Leverett J-Function for the Dune and Yates Carbonate Fields: A Case Study

Effective medium theory (EMT) has been used to model capillary pressure (Pc) as a function of water saturation (Sw) in porous media. The EMT model results show that both the magnitude and profile of the Pc − Sw profile are strongly affected by changing the pore-size distribution parameters and the rock pore geometry. Tortuosity, which is a function of these parameters, is used in developing a drainage capillary pressure model based on data from the Dune and Yates fields. Capillary pressure is normalized with respect to an average pore radius that includes tortuosity. To minimize the uncertainty caused by the contact angle term, only helium/water capillary pressure curves were considered. The wetting-phase saturation is normalized with respect to an asymptotic irreducible wetting-phase saturation. For the Dune and Yates fields, the development of this type of dimensionless model may be useful as an input for reservoir simulation studies.

Evaluation of the High-Speed Centrifuge Technique for Determining Capillary Pressure at Low Wetting-Phase Saturations

ABSTRACTRecent experimental studies of the high-speed centrifuge technique have indicated that the method, if properly used, yields results which are in accordance with other methods. These studies have also shown that the concept of an irreducible wetting phase saturation is not valid. In the present paper work is reported in which these previously presented results are extended to both higher and lower capillary pressures. Air/liquid data have been obtained with n-decane as the wetting phase and are compared with new data (as well as with the previously reported data) for the air/brine system. The study involved 242 days of centrifugation and utilized 10 different Berea plug samples and 5 different high permeability plug samples taken from a producing reservoir.The linear relationship between log Pc and log &amp;lt;Sw&amp;gt; (or log Sw, as observed in previous work) was confirmed for Berea samples over the average saturation range from about 30 percent down to 10 percent. For lower average saturations, the saturation data are not sufficiently precise either to (1) demonstrate conclusively the persistence of this relationship, or (2) prove the breakdown of the Hassler boundary condition. For three of the five producing reservoir samples, it was found that two different linear segments characterized the log Pc versus log &amp;lt;Sw&amp;gt; relationship, with a rather sharp transition occurring in the 30 to 40 percent average saturation range.

Interpretation of capillary pressure curves using invasion percolation theory

Invasion percolation was studied on three-dimensional regular lattices of various node numbers. A new model has been developed to obtain the pore-size distribution from capillary pressure measurements. The new model is superior to the conventional percolation model, since it takes into account the physical trapping of the wetting phase. The irreducible wetting phase saturation includes the film of the wall of the pores, the dead-end pore volume, and the main contribution by pores isolated from the outlet of the medium by the nonwetting phase. This has been related to the node number and the sample 3dimensions. Over 100 capillary pressure curves of consolidated media have been collected. Good agreement was obtained between this data set out and our invasion percolation predictions using node numbers of 6–13, as reported by Mishra and Sharma. The pore-throat size distribution function estimated by our new model is broader than from the conventional percolation and the capillary tube models.

Capillary pressure behavior in pores with curved triangular cross-section: Effect of wettability and pore size distribution

The capillary behavior of two immiscible fluids in pores of angular cross-section differs appreciably from that in pores of circular cross-section. We have extended the work of Mason and Morrow [G. Mason and N.R. Morrow, J. Colloid Interface Sci., 141 (1991) 262; N.R. Morrow, Paper presented at 1st Int. Symp. on Evaluation of Reservoir Wettability and Its Effect on Oil Recovery, Socorro, NM, September 18–21, 1990] to pores whose cross-section is a triangle with curved, rather than straight, sides. Capillary pressure vs saturation curves were obtained for single pores, as well as for bundles of parallel pores with log-normal pore size distributions of varying geometric standard deviation. Wettability, as expressed by the contact angle, was varied also. In many ways, the computed behavior is qualitatively similar to that observed for real porous media, such as petroleum reservoir rocks. That is, there is drainage—imbibition hysteresis, a residual non-wetting-phase saturation upon imbibition, and a reversal in the sign of the capillary pressure upon imbibition in systems that approach neutral wettability. However, because of the lack of network effects, there is no mechanism for a true irreducible wetting-phase saturation. It seems likely that, to capture all aspects of multifluid behavior in real porous media (capillary pressure, relative permeabilities, electrical resistivity, etc.), models of such media should not only be based on networks but must also incorporate pore angularity.