Pore-scale Fluid Distribution Research Articles

In-situ characterization of capillary pressure during three-phase flow in porous media

We characterize the pore-scale fluid distributions, phase connectivity, and local capillary pressures during three-phase flow in a water-wet Berea sandstone sample. In this investigation, we use a set of x-ray micro-tomography images acquired during three-phase core-flooding experiments conducted on a miniature core sample. We use several image analysis techniques to analyze the pore-scale fluid occupancy maps and use this information to develop several insights related to pore occupancy, oil and gas cluster distribution, and interfacial curvature during the gas injection process. The results of our investigation show that the large-, intermediate-, and small-sized pores are mostly occupied with gas, oil, and brine, respectively, which is consistent with the wetting order of the fluids (i.e., gas, oil, and brine are the nonwetting, intermediate wetting, and wetting phases, respectively). In addition, the connectivity analysis reveals that a significant amount of the gas phase was in the form of disconnected ganglia separated from the connected invading cluster. The presence of these trapped nonwetting phase clusters during the drainage process is presumably attributed to Roof snap-off and Haines jump events, as well as the anti-ripening phenomenon. Moreover, the average local oil-water capillary pressures are found to be greater than the gas-oil counterparts. This observation is then related to the relative location of the interfaces in the pore space and the threshold capillary pressures at which the various displacement events take place.

Modeling drainage in porous media considering locally variable contact angle based on pore morphology method

• A new pore morphology method, Lvca–PMM, is proposed. • Lvca–PMM considers locally variable contact angles. • Lvca–PMM can produce the capillary pressure–saturation curves. • Contact angles and fluid distributions can be well simulated by Lvca–PMM. • Lvca–PMM presents better results than the method by Schulz et al (2014). The pore morphology method (PMM) has been widely applied to simulate the quasi–static drainage process of porous media, which requires less computational time and computer memory compared to other two–phase flow simulation methods. However, most of the existing pore morphology simulations were restricted to totally wetting systems (i.e., contact angle is equal to zero). Here, we propose a new pore morphology method (Lvca–PMM) enhanced by considering locally variable contact angles, which now enables a reproduction of the primary drainage process for porous media under different wettability conditions featuring the full range of contact angle for wetting phase for various spatial distribution. A series of simulations are performed by using the Lvca–PMM to a porous medium under different uniform and mixed wettability conditions. The proposed Lvca–PMM presents a better result compared to the method by Schulz et al. (2014) for different wettability conditions. The capillary pressure–saturation relations as well as the pore–scale fluid distributions can be well captured by the proposed Lvca-PMM.

Rock-fluid interfacial tension at subsurface conditions: Implications for H2, CO2 and natural gas geo-storage

In H2, CO2 and natural gas geo-storage, rock-fluid interfacial tension (γrock−fluid) is a key parameter which influences pore-scale fluid distribution and reservoir-scale gas storage capacity and containment security. However, γrock−fluid data is seriously lacking because of the inability to measure this parameter experimentally. Therefore herein, a semi-empirical method is used to calculate γrock−fluid at geo-storage conditions. Additionally, effects of organic acid and silica nanofluid on γrock−fluid are studied. The following results are obtained. γrock−gas decreases with pressure, temperature, organic acid concentration and carbon number increase, while γrock−H2O increases with organic acid concentration and carbon number increase; γrock−gas first increases and subsequently decreases with silica nanofluid concentration increase, while γrock−H2O first decreases and then increases with silica nanofluid concentration increase; for same thermo-physical and rock surface chemistry conditions, γrock−gas follows the order H2 > CH4 > CO2. These insights provide pivotal guidance on gas geo-storage and thus aids in the implementation of a more sustainable energy supply chain.

The LBPM software package for simulating multiphase flow on digital images of porous rocks

Direct pore scale simulations of two-fluid flow on digital rock images provide a promising tool to understand the role of surface wetting phenomena on flow and transport in geologic reservoirs. We present computational protocols that mimic conventional special core analysis laboratory (SCAL) experiments, which are implemented within the open source LBPM software package. Protocols are described to simulate unsteady displacement, steady-state flow at fixed saturation, and to mimic centrifuge experiments. These methods can be used to infer relative permeability and capillary curves, and otherwise understand two-fluid flow behavior based on first principles. Morphological tools are applied to assess image resolution, establish initial conditions, and instantiate surface wetting maps based on the distribution of fluids. Internal analysis tools are described that measure essential aspects of two-fluid flow, including fluid connectivity and surface measures, which are used to track transient aspects of the flow behavior as they occur during simulation. Computationally efficient workflows are developed by combining these components with a two-fluid lattice Boltzmann model to define hybrid methods that can accelerate computations by using morphological tools to incrementally evolve the pore-scale fluid distribution. We show that the described methods can be applied to recover expected trends due to the surface wetting properties based on flow simulation in Benntheimer sandstone.

Modeling Geometric State for Fluids in Porous Media: Evolution of the Euler Characteristic

Multiphase flow in porous media is strongly influenced by the pore-scale arrangement of fluids. Reservoir-scale constitutive relationships capture these effects in a phenomenological way, relying only on fluid saturation to characterize the macroscopic behavior. Working toward a more rigorous framework, we make use of the fact that the momentary state of such a system is uniquely characterized by the geometry of the pore-scale fluid distribution. We consider how fluids evolve as they undergo topological changes induced by pore-scale displacement events. Changes to the topology of an object are fundamentally discrete events. We describe how discontinuities arise, characterize the possible topological transformations and analyze the associated source terms based on geometric evolution equations. Geometric evolution is shown to be hierarchical in nature, with a topological source term that constrains how a structure can evolve with time. The challenge associated with predicting topological changes is addressed by constructing a universal geometric state function that predicts the possible states based on a non-dimensional relationship with two degrees of freedom. The approach is validated using fluid configurations from both capillary and viscous regimes in ten different porous media with porosity between 0.10 and 0.38. We show that the non-dimensional relationship is independent of both the material type and flow regime. We demonstrate that the state function can be used to predict history-dependent behavior associated with the evolution of the Euler characteristic during two-fluid flow.

Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock

Differential imaging X-ray microtomography combined with a steady-state flow apparatus was used to elucidate the displacement processes during waterflooding. We simultaneously measured relative permeability and capillary pressure on a carbonate rock sample extracted from a giant producing oil field. We used the pore-scale images of crude oil and brine to measure the interfacial curvature from which the local capillary pressure was calculated; the relative permeability was found from the imposed fractional flow, the image-measured saturation, and the pressure differential across the sample.The relative permeabilities indicated favourable oil recovery for the mixed-wettability conditions. The pore-scale images showed that brine started to flow through pinned wetting layers, micro-porosity and water-wet pores, and then filled the centre of the larger oil-wet pores. Oil was drained to low saturation through connected oil layers. The brine relative permeability remained low until brine invaded a connected pathway of smaller throats at a high brine saturation. The interface between the oil and brine had a small average curvature, indicating a low capillary pressure, but we observed remarkable saddle-shaped interfaces with nearly equal but opposite curvatures in orthogonal directions. This implies good oil phase connectivity, consistent with the favourable recovery and low residual oil saturation attained in the experiments.This work illuminated displacement processes from both macro-pores and micro-pores which have important implications for improved oil recovery and, potentially, on carbon storage. In future, the measured relative permeability, capillary pressure and pore-scale fluid distribution could be used to benchmark and validate pore-scale models.

Microscale Investigation of the Impact of Surfactant Structure on the Residual Trapping in Natural Porous Media

Residual trapping of a nonwetting phase in a porous medium is directly impacted by the relative magnitude of capillary, viscous, and gravity forces. Ratios of these forces control the sequence by which different pore-scale displacement mechanisms take place, which in turn govern the pore fluid occupancy and the residual nonwetting phase saturation. Parameters such as pore geometry, rock surface wettability, fluid–fluid interfacial tension, and fluids’ viscosities, densities, and flow rates determine the magnitude of the above-mentioned forces. In this study, we show that there is an additional set of factors that directly contributes to the distribution of fluids at the pore scale. We demonstrate that, under similar rock and fluid properties, interfacial repulsive and attractive interactions, caused by the adsorption of surface-active chemicals on fluid–fluid interfaces, can significantly alter pore-scale fluid occupancies. Using the microcomputed tomography (micro-CT) imaging technique integrated with a miniature core-flooding apparatus, we investigate the impact of surfactant structure on pore-scale fluid distributions in a limestone core sample subjected to injection of different wetting fluid solutions. Poly(ethylene oxide) (PEO), a nonionic surfactant, and ammonium alkyl ether sulfate, an anionic surfactant, are utilized as surface-active agents providing similar oil–brine interfacial tension (IFT) and contact angle (CA) values. Oil cluster analyses along with three-dimensional (3D) visualization of fluid distributions indicate that using the nonionic surfactant instead of the anionic surfactant results in the breaking up of the large and medium oil clusters into smaller and scattered ones. We propose a mechanism relating the stability of oil–brine interface to surfactant structure that is responsible for the breakup and/or coalescence of oil clusters inside the pore space. The suggested mechanism is confirmed by the micro-CT images and associated oil cluster analyses. This phenomenon affects the competition between the frequency of displacement mechanisms causing variations in remaining oil saturations.

Pore-scale fluid distributions determined by nuclear magnetic resonance spectra of partially saturated sandstones

The acoustic property and the P-wave velocity of partially saturated rocks depend not only on the water saturation but also on the pore-scale fluid distribution. Here, we analyzed the pore-scale fluid distribution using nuclear magnetic resonance (NMR) [Formula: see text] spectra, which present the variation of porosity components associated with NMR transverse relaxation time [Formula: see text]. Based on the [Formula: see text] spectra, we classified the pore-scale fluid distribution during water imbibition and drainage into three models: a low-saturation model, a patchy distribution model, and a uniform distribution model. We specifically assigned the low-saturation model to deal with the acoustic property of the rocks at the imbibition starting stage and the drainage final stage because cement softening has a nonnegligible effect. We studied the acoustic properties of sandstone rocks with various pore-scale fluid distributions, at the imbibition process and the drainage process. We confirmed that, once the variations in water saturation and pore-scale fluid distribution are taken into account, the P-wave velocity prediction matches well with the laboratory measurement of samples, representing nearly tight sandstone rocks that are partially saturated with distilled water.

Generation of ground truth images to validate micro-CT image-processing pipelines

Digital rock technology and pore-scale physics have become increasingly relevant topics in a wide range of porous media with important applications in subsurface engineering. This technology relies heavily on images of pore space and pore-level fluid distribution determined by X-ray microcomputed tomography (micro-CT). Digital images of pore space (or pore-scale fluid distribution) are typically obtained as gray-level images that first need to be processed and segmented to obtain the binary images that uniquely represent rock and pore (including fluid phases). This processing step is not trivial. Rock complexity, image quality, noise, and other artifacts prohibit the use of a standard processing workflow. Instead, an array of strategies of increasing sophistication has been developed. Typical processing pipelines consist of filtering, segmentation, and postprocessing steps. For each step, various choices and different options exist. This makes selection and validation of an optimum processing pipeline difficult. Using Darcy-scale quantities as a benchmark is not a good option because of rock heterogeneity and different scales of observation. Here, we present a conceptual workflow where noisy images are derived from a ground truth by systematically including typical image artifacts and noise. Artifacts and noise are not simply added to the images. Instead, tomographic forward projection and reconstruction steps are used to incorporate the artifacts in a physically correct way. A proof of concept of this workflow is demonstrated by comparing seven different image-segmentation pipelines ranging from absolute thresholding to a machine-learning approach (Trainable Weka Segmentation). The Trainable Weka Segmentation showed the best performance of the tested methods.

Validation of model predictions of pore-scale fluid distributions during two-phase flow

Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.

Micro-scale experimental investigation of the effect of flow rate on trapping in sandstone and carbonate rock samples

We present the results of a pore-scale experimental study of residual trapping in consolidated sandstone and carbonate rock samples under confining stress. We investigate how the changes in wetting phase flow rate impacts pore-scale distribution of fluids during imbibition in natural, water-wet porous media. We systematically study pore-scale trapping of the nonwetting phase as well as size and distribution of its disconnected globules. Seven sets of drainage-imbibition experiments were performed with brine and oil as the wetting and nonwetting phases, respectively. We utilized a two-phase miniature core-flooding apparatus integrated with an X-ray microtomography system to examine pore-scale fluid distributions in small Bentheimer sandstone (D = 4.9 mm and L = 13 mm) and Gambier limestone (D = 4.4 mm and L = 75 mm) core samples. The results show that with increase in capillary number, the residual oil saturation at the end of the imbibition reduces from 0.46 to 0.20 in Bemtheimer sandstone and from 0.46 to 0.28 in Gambier limestone. We use pore-scale displacement mechanisms, in-situ wettability characteristics, and pore size distribution information to explain the observed capillary desaturation trends. The reduction was believed to be caused by alteration of the order in which pore-scale displacements took place during imbibition. Furthermore, increase in capillary number produced significantly different pore-scale fluid distributions during imbibition. We explored the pore fluid occupancies and studied size and distribution of the trapped oil clusters during different imbibition experiments. The results clearly show that as the capillary number increases, imbibition produces smaller trapped oil globules. In other words, the volume of individual trapped oil globules decreased at higher brine flow rates. Finally, we observed that the pore space in the limestone sample was considerably altered through matrix dissolution at extremely high brine flow rates. This increased the sample porosity from 44% to 62% and permeability from 7.3 D to 80 D. Imbibition in the altered pore space produced lower residual oil saturation (from 0.28 to 0.22) and significantly different distribution of trapped oil globules.

Connected pathway relative permeability from pore-scale imaging of imbibition

Pore-scale images obtained from a synchrotron-based X-ray computed micro-tomography (µCT) imbibition experiment in sandstone rock were used to conduct Navier–Stokes flow simulations on the connected pathways of water and oil phases. The resulting relative permeability was compared with steady-state Darcy-scale imbibition experiments on 5cm large twin samples from the same outcrop sandstone material. While the relative permeability curves display a large degree of similarity, the endpoint saturations for the µCT data are 10% in saturation units higher than the experimental data. However, the two datasets match well when normalizing to the mobile saturation range. The agreement is particularly good at low water saturations, where the oil is predominantly connected. Apart from different saturation endpoints, in this particular experiment where connected pathway flow dominates, the discrepancies between pore-scale connected pathway flow simulations and Darcy-scale steady-state data are minor overall and have very little impact on fractional flow. The results also indicate that if the pore-scale fluid distributions are available and the amount of disconnected non-wetting phase is low, quasi-static flow simulations may be sufficient to compute relative permeability. When pore-scale fluid distributions are not available, fluid distributions can be obtained from a morphological approach, which approximates capillary-dominated displacement. The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed. The morphological approach does not represent the imbibition process very well and experimental data for the spatial arrangement of the phases are required. Presumably for modeling imbibition relative permeability an approach is needed that captures moving liquid-liquid interfaces, which requires viscous and capillary forces simultaneously.

Subsecond pore-scale displacement processes and relaxation dynamics in multiphase flow.

With recent advances at X-ray microcomputed tomography (μCT) synchrotron beam lines, it is now possible to study pore-scale flow in porous rock under dynamic flow conditions. The collection of four-dimensional data allows for the direct 3-D visualization of fluid-fluid displacement in porous rock as a function of time. However, even state-of-the-art fast-μCT scans require between one and a few seconds to complete and the much faster fluid movement occurring during that time interval is manifested as imaging artifacts in the reconstructed 3-D volume. We present an approach to analyze the 2-D radiograph data collected during fast-μCT to study the pore-scale displacement dynamics on the time scale of 40 ms which is near the intrinsic time scale of individual Haines jumps. We present a methodology to identify the time intervals at which pore-scale displacement events in the observed field of view occur and hence, how reconstruction intervals can be chosen to avoid fluid-movement-induced reconstruction artifacts. We further quantify the size, order, frequency, and location of fluid-fluid displacement at the millisecond time scale. We observe that after a displacement event, the pore-scale fluid distribution relaxes to (quasi-) equilibrium in cascades of pore-scale fluid rearrangements with an average relaxation time for the whole cascade between 0.5 and 2.0 s. These findings help to identify the flow regimes and intrinsic time and length scales relevant to fractional flow. While the focus of the work is in the context of multiphase flow, the approach could be applied to many different μCT applications where morphological changes occur at a time scale less than that required for collecting a μCT scan.

Relative permeability of homogenous-wet and mixed-wet porous media as determined by pore-scale lattice Boltzmann modeling

We present a pore-scale study of two-phase relative permeability in homogenous-wet porous media, and porous media altered to a mixed-wet state. A Shan-Chen type multicomponent lattice Boltzmann (LB) model is employed to determine pore-scale fluid distributions and relative permeability. Mixed-wet states are created by altering the wettability of solid surfaces in contact with the nonwetting phase at the end of steady state simulation of initially homogenous-wet porous media. To ensure accurate representation of fluid-solid interfacial areas, we compare LB simulation results to experimental measurements of interfacial fluid-fluid and fluid-solid areas determined by X-ray computed microtomography imaging of water and oil distributions in bead packs. The LB simulations are found to match experimental trends observed for fluid-fluid and fluid-solid interfacial area-saturation relationships. The relative permeability of both fluids in the homogenous-wet porous media was found to decrease with a decreasing contact angle. The relative permeability of both fluids in the altered, mixed-wet porous media was found to decrease for all mixed-wet states in comparison to the initial homogenous-wet states. The nonwetting phase relative permeability decreased significantly, while the wetting phase experienced only a minor decrease. The significance of the decrease was found to be dependent on the distribution of the unaltered solid surfaces, with less dependence on the severity of alteration.

Visualisation of Residual Oil Recovery by Near-miscible Gas and SWAG Injection Using High-pressure Micromodels

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).

Dynamic network modeling of two-phase drainage in porous media

We present a dynamic network model for modeling two-phase flow. We account for wetting layer flow, meniscus oscillation, and the dynamics of snapoff. Interfaces are tracked through pore elements using a modified Poiseuille equation for the equivalent hydraulic resistance of the fluids between the pore element centers. The model is used to investigate the effects of capillary number and viscosity ratio on displacement patterns and fractional flow in primary drainage. We show that the amount of snapoff increases with increasing capillary number and decreasing wetting phase viscosity. For capillary numbers lower than approximately 10(-5), the pore-scale fluid distribution and fractional flow are similar to those obtained using a quasistatic model that ignores viscous forces. The contribution of oil transport from ganglia, formed by snapoff, is negligible except for very large capillary numbers, greater than around 0.1.

Wettability of reservoir rock and fluid systems from complex resistivity measurements

Electrical resistivity measurements at a single low AC frequency have long been recognized as providing an indication of the wettability of reservoir rock and fluid systems. However, the resistivity response over a range of frequencies for samples of varying wettability is not so well characterized. Data is presented from reservoir core plugs of differing lithologies, permeabilities, and wettabilities. The complex resistivity response at differing saturations and wettability was measured. This research group has been investigating relationships between complex resistivity, permeability, and clay content, described in previous research papers. This study extends this work to include wettability. Electrical resistivity measurements in the low-frequency range (10 Hz–10 kHz) include an electrode polarization effect. At frequencies between 10 and 200 kHz, the electrode polarization effect is reduced and the bulk sample response measured. An Argand diagram analysis is employed to find the critical frequency ( f c) separating the electrode polarization from the bulk sample response. Samples are tested in a multi-sample rig at hydrostatic reservoir overburden stresses. The test equipment allows the measurement of resistivity in the two or four electrode configurations over a frequency range from 10 Hz to 1 MHz during drainage and imbibition cycles. Multi-electrodes down the sample length allow saturation monitoring and thus the detection of any saturation inhomogeneity throughout the samples. Sample wettability is evaluated using the Amott–Harvey wettability index (AHWI) on adjacent samples and change in Archie Saturation exponent before and after aging in crude oil. The effect of frequency dispersion was analysed in relation to pore-scale fluid distribution and, hence, wettability. The results suggest complex resistivity measurement have the potential as a non-invasive technique to evaluate reservoir wettability.

Pore-scale network model for drainage-dominated three-phase flow in porous media

Drainage displacements in three-phase flow under strongly wetting conditions are completely described by a simple generalisation of well understood two-phase drainage mechanisms. As in two-phase flow, the sequence of throat invasions in three-phase flow is determined by fluid connectivity and threshold capillary pressure for the invading interface. Flow through wetting and intermediate spreading films is important in determining fluid recoveries and the progress of the displacement in three-phase flow. Viscous pressure drops associated with flow through films give rise to multiple filling and emptying of pores. A three-phase, two-dimensional network model based on the pore-scale fluid distributions and displacement mechanisms reported by Oren et al. and which accounts for flow through both wetting and intermediate fluid films is shown to correctly predict all the important characteristics of three-phase flow observed in glass micromodel experiments.

The effects of pore-scale fluid distribution on the physical properties of partially saturated tight sandstones

Pore-scale fluid distribution has a significant effect on the physical properties of a partially saturated porous medium. Experimental data for the dielectric response and elastic wave velocities for a tight gas sandstone undergoing a cycle of water saturation change through imbibition and drainage are analyzed. Mathematical formulations describing the internal geometrical configuration of a porous medium in terms of a rock matrix background with embedded oblate spheroidal inclusions representing the porosity are used to theoretically predict the dielectric constant and elastic wave velocities of the partially saturated sandstone. Simple geometrical models, incorporating homogeneous and heterogeneous inclusions, are used to simulate the pore-scale fluid distribution which should result from the two saturation methods employed. It is found that these simple scenarios accurately predict the functional form and magnitude of the observed saturation-induced hysteresis in the experimental data for both the dielectric constant and the elastic wave velocities.

A laboratory study of the dependence of elastic wave velocities on pore scale fluid distribution

Laboratory data have been collected during a continuous imbibition/drainage experiment that show a clear dependence of elastic wave velocities on the details of the pore scale distribution of water and air in a sandstone. Compressional wave velocity (Vp) was measured at a frequency of 1 MHz; shear wave velocity (Vs) was measured at a frequency of 600 kHz. During the experiment, Vp showed little variation with the level of water saturation (Sw) during increasing Sw through imbibition until Sw = 0.80, at which point Vp increased dramatically. When Sw was decreased, pronounced saturation‐induced hysteresis was observed in the region 03 < Sw < 0.9, with Vp measured during drainage greater than Vp measured during imbibition. Similar results were obtained for Vs versus Sw, with Vs during drainage greater that Vs during imbibition in the saturation range Sw > 0.4.As a simple model, we consider the imbibition process as producing a partially saturated state in all pores; i.e. all pores contain both air and water. The drainage process, in contrast, favors the existence of either air‐filled or water‐filled pores. As elastic wave velocities are very sensitive to the saturation state in the smaller, “crack‐like” pores, these variations in fluid distribution cause related variations in velocities.