Relative Permeability Saturation Research Articles

Upscaling and Effective Behavior for Two-Phase Porous-Medium Flow Using a Diffuse Interface Model

We investigate two-phase flow in porous media and derive a two-scale model, which incorporates pore-scale phase distribution and surface tension into the effective behavior at the larger Darcy scale. The free-boundary problem at the pore scale is modeled using a diffuse interface approach in the form of a coupled Allen–Cahn Navier–Stokes system with an additional momentum flux due to surface tension forces. Using periodic homogenization and formal asymptotic expansions, a two-scale model with cell problems for phase evolution and velocity contributions is derived. We investigate the computed effective parameters and their relation to the saturation for different fluid distributions, in comparison to commonly used relative permeability saturation curves. The two-scale model yields non-monotone relations for relative permeability and saturation. The strong dependence on local fluid distribution and effects captured by the cell problems highlights the importance of incorporating pore-scale information into the macro-scale equations.

Sulfonamide Derivatives as Novel Surfactant/Alkaline Flooding Processes for Improving Oil Recovery.

Over time, oil consumption has increased along with a continuous demand for petroleum products that require finding ways to increase hydrocarbon production more economically and effectively. So, enhanced oil recovery technologies are believed to be very promising and will serve as a key to meeting the future energy demand. This paper aims to introduce an innovative method to boost the EOR by using two novel types of surfactants synthesized from sulfonamide derivatives. Types I and II surfactants were analyzed using Fourier transform infrared spectroscopy, and their characterization was further performed using 1H NMR and 13C NMR spectroscopy. Additionally, the evaluation of these surfactants included interfacial tension measurements at concentrations up to 0.9 wt %. The combination of types I and II surfactants with alkaline (NaOH) was also investigated by the measurements of interfacial tension. A series of coreflood and sandpack tests under high-salinity conditions were carried out to assess the effects of a surfactant alone and alkaline-surfactant as a combination on improving oil recovery. The rock wettability was evaluated using relative permeability saturation curves, and the oil displacement efficiency was determined using fractional flow curves. The coreflood results demonstrated that alkaline-surfactant flooding with the chemical formula 0.2 wt % surfactant type II plus 0.5 wt % NaOH achieved a higher oil recovery of 74% OOIP compared to surfactant flooding with the chemical formula 0.5 wt % surfactant type II (64% OOIP) and waterflooding (saline solution with a 35,000 ppm salinity: 48% OOIP). Moreover, the experimental results showed that under both core and sandpack flood conditions, there was a noticeable reduction in oil-water interfacial tension, a change in rock wettability to more water-wet, and higher efficiency of oil displacement when alkaline was added to the surfactant. Based on current research, the alkaline-surfactant formulation is strongly recommended for chemical flooding because of its high efficacy and relatively low cost.

Experimental Study on Gas–Water Relative Permeability Characteristics of Tight Sandstone Reservoir in Ordos Basin

Accurate measurement of relative permeability curve is the basis for evaluating gas reservoir performance. The unsteady-state method could bring significant measurement error for low-permeability cores. However, it is difficult to control the constant gas flow rate in the traditional steady-state method, which obstacles the experimental operation. In this study, an improved steady-state method was proposed. First, the pressure value obtained from the experiment, when the gas permeability no longer changed with the average pressure on the rock core, was set as the testing pressure. Then, the gas was injected under constant pressure, and the water was injected with a constant flow rate. Finally, the relative permeability values of gas and water phases were calculated based on Darcy’s law. Comparative analysis of the results of the relative permeability curves under formation pressure and pressure with negligible slip effect indicates that the relative permeability curves are the same in gas and water phases, proving the feasibility of the new method. Further, the results were compared with those of the test method at normal pressure, the water-phase relative permeability showed no significant change, the relative permeability of gas phase was larger, the two-phase flow area became wider, and the irreducible water saturation was lower than that at the normal pressure. This result reflects that pressure does not significantly affect the flow of wetting phase but tremendously influences the nonwetted phase under low pressure. The relationship between relative permeability and water saturation is linear in the semilogarithmic coordinate diagram and can be described by using the following relationship: ln k rg / k rw = a S w + ln b . With the decrease in the core permeability, relative permeability curve, and isotonic point moved to the right, irreducible water saturation gradually increased, and residual gas saturation decreased, indicating that the smaller permeability induced a lower gas-phase flow capacity.

Two‐Phase Relative Permeability of Rough‐Walled Fractures: A Dynamic Pore‐Scale Modeling of the Effects of Aperture Geometry

AbstractAn accurate description of the relative permeability–saturation function is crucial for reliable predictions of multi‐phase flow behavior in subsurface applications. Although extensive efforts have been put forth to investigate the relative permeability behavior in different types of porous media, only few studies have focused on rough‐walled fractures. In this work, we present an entirely new, cost‐effective, heavily‐parallelized, dynamic pore‐network modeling framework that is employed to conduct a systematic study of relative permeability curves under two‐phase flow conditions in rough‐walled fractures. We first build a two‐dimensional (101.42 × 24.86 mm2) equivalent pore network of a Berea sandstone fracture from its x‐ray images. Subsequently, dynamic primary drainage and imbibition simulations are conducted in the fracture. We show that the two‐phase fluid occupancy maps predicted from the simulations agree well with the fracture fluid configurations obtained via X‐ray computed tomography. Afterward, the validated model is used to probe two‐phase flow properties in a series of synthetic aperture fields generated with a broad range of geometric characteristics including aperture spatial correlation length (normalized correlation length varying from 0.05 to 0.95), anisotropy factor (0.25–4), surface roughness (normalized fracture roughness varying from 0.05 to 0.4), and mean aperture size (50–800 μm). The generated results provide novel insights into the effects of these features on two‐phase flow properties such as fluid–fluid interfacial area, phase interference, and relative permeability. Moreover, based on the simulation results we propose two new correlations to describe the relative permeability curves for primary drainage and imbibition processes in rough‐walled fractures.

Guar Gum-Based Hydrogels as Potent Green Polymers for Enhanced Oil Recovery in High-Salinity Reservoirs.

Improving oil production for high-salinity reservoirs using polymer flooding is challenging due to chemical and mechanical degradations. This study developed two biodegradable biopolymers based on graft copolymerization of guar gum (GG) with two different co-monomers, which are acrylamide (Am) and 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and cross-linked by N,N′-methylene bisacrylamide (MBA) to face these challenges. The newly synthesized guar gum-based hydrogels, GG-g-poly(Am-AMPS) (GH) and GG-g-poly(Am-AMPS)/Biochar (GBH composite), were evaluated as potential candidates for enhanced oil recovery (EOR) under high-salinity conditions. Fourier transform infrared (FTIR) spectroscopy and thermogravimetric analysis (TGA) of the synthesized hydrogels were investigated, and their rheological properties were measured at room temperature. Both GH and GHB display a shear-thinning performance. In polymer flooding experiments, guar gum hydrogel (GH) and guar gum/biochar composite hydrogel (GHB) showed a remarkable influence on delaying the water breakthrough and proved to be effective biopolymers for enhanced oil recovery in high-salinity reservoirs. At the optimum concentration of 5 g/L, GH flooding achieved maximum oil recoveries of 70.53 and 72.11% in secondary and tertiary recovery processes, respectively. Meanwhile, the waterflooding process achieved an ultimate oil recovery of 58.42%. GHB flooding at optimum concentration, 2 g/L, increased the amount of oil recovery by 8.95% in tertiary recovery compared to waterflooding. Furthermore, GH (5 g/L) and GHB (2 g/L) slightly enhanced the rock water wettability as confirmed by contact angle measurements for GH and the relative permeability saturation curves for GH and GHB.

Modeling of relative permeabilities including dynamic wettability transition zones

Wettability is a pore-scale property that impacts the relative movement and distribution of fluids in a porous medium. There are reservoir fluids that provoke the surface within pores to undergo a wettability change. This wettability change, in turn, alters the dynamics of relative permeabilities at the Darcy scale. Thus, modeling the impact of wettability change in the relative permeabilities is essential to understand fluids interaction in porous media. In this study, we include time-dependent wettability change into the relative permeability–saturation relation by modifying the existing relative permeability function. To do so, we assume the wettability change is represented by the sorption-based model that is exposure time and chemistry dependent. This pore-scale model is then coupled with a triangular bundle-of-tubes model to simulate exposure time-dependent relative permeabilities data. The simulated data is used to characterize and quantify the wettability dynamics in the relative permeability–saturation curves. This study further shows the importance of accurate prediction of the relative permeability in a dynamically altering porous medium.

Effects of topological disorder in unsaturated granular media via a pore-scale lattice Boltzmann investigation

In this study, we investigate the impact of topological disorder on liquid distribution and transport phenomena in three-dimensional unsaturated granular media using the Shan-Chen lattice Boltzmann method. Distinct samples of disordered media are generated, characterized by the disorder index Iv. Under different Iv, varied liquid cluster distributions are demonstrated in a gravity-driven vapour-liquid system. Gradually increasing the initial liquid phase in the simulation domain allows the full range of saturation. The focuses are placed on the liquid cluster statistics from the connectivity, total cluster number, largest cluster and mean cluster volume at an increasing saturation. Meanwhile, the interfacial area, liquid retention curves and relative permeability-saturation curves are produced at diverse Iv and wettability. It is found that the slopes of retention curves are well correlated with the proposed capillary index Ic that unifies both disorder and wettability. The proposed generalized correlation between capillary index and slope index is useful in terms of determining the capillary pressure-saturation curve and relative permeability-saturation curve for a given granular system at varied contact angles. Additionally, the cohesive strength-saturation curves are also obtained with the aid of the interfacial area and negative capillary pressure, which elucidates that a packing with a higher Iv experiences a relatively larger cohesive strength. These results enhance the understanding of disorder effect and will be beneficial for the exploration of many retention curves-related phenomena such as liquid transfer and stress-strain relation for wet granular media.

Synchrotron-based pore-network modeling of two-phase flow in Nubian Sandstone and implications for capillary trapping of carbon dioxide

Depleted oil fields in the Gulf of Suez (Egypt) can serve as geothermal reservoirs for power generation using a CO2-Plume Geothermal (CPG) system, while geologically sequestering CO2. This entails the injection of a substantial amount of CO2 into the highly permeable brine-saturated Nubian Sandstone. Numerical models of two-phase flow processes are indispensable for predicting the CO2-plume migration at a representative geological scale. Such models require reliable constitutive relationships, including relative permeability and capillary pressure curves. In this study, quasi-static pore-network modelling has been used to simulate the equilibrium positions of fluid–fluid interfaces, and thus determine the capillary pressure and relative permeability curves.Three-dimensional images with a voxel size of 0.65 μm3 of a Nubian Sandstone rock sample have been obtained using Synchrotron Radiation X-ray Tomographic Microscopy. From the images, topological properties of pores/throats were constructed. Using a pore-network model, we performed a sequential primary drainage, main imbibition cycle of quasi-static invasion in order to quantify (1) the CO2 and brine relative permeability curves, (2) the effect of initial wetting-phase saturation (i.e. the saturation at the point of reversal from drainage to imbibition) on the residual-trapping potential, and (3) study the relative permeability-saturation hysteresis. The results improve our understanding of the potential magnitude of capillary trapping in Nubian Sandstone, essential for future field-scale simulations.

Water freezing characteristics in granular soils: Insights from pore-scale simulations

It has been observed in both laboratory and field studies that unfrozen soil moisture content is hysteretic between freezing and thawing conditions. While a few explanations have been provided for the causes of this hysteresis, there is no general agreement in the literature on underlying causal mechanisms. In this study, we use pore-scale simulations to investigate the role that contact angle hysteresis during freezing and thawing conditions may play in the observed differences in soil moisture content during freezing and thawing conditions. We also use these pore-scale simulations to better assess the similarities between freezing and water drainage processes in pore space as such realistic assessments are very limited in the literature. Specifically, we use 3D images of natural sand packs and synthetic silicates to generate pore-scale model domains and to simulate water drainage and water freezing in the soil pore space. The simulated water drainage curve and relative permeability-saturation relations for the sand packs agrees well with measured data available in the literature for sandy soils. The simulated soil freezing curves were successfully converted to simulated water drainage curve confirming conclusions of previous studies on coarse granular soils. Water freezing simulations using different contact angles for freezing (water receding) and thawing (water advancing) showed that the hysteresis in soil freezing curves could be driven by a hysteresis in the contact angle of water-ice interface at the pore wall (i.e. grain surface). In addition, simulations of water drainage in partially frozen soils revealed that soil freezing enhances liquid water retention in pore space due to reduction of mean active pore radius and increased frequency of pore corners which agrees with the observations of published studies in laboratory and field conditions.

Two-phase flow of CO2-brine in a heterogeneous sandstone: Characterization of the rock and comparison of the lattice-Boltzmann, pore-network, and direct numerical simulation methods

Understanding the physics of two-phase flow of CO2 and brine in porous geological formations is essential to sequestration of carbon dioxide in deep saline reservoirs, as well as the older problem of enhanced oil recovery from hydrocarbon reservoirs by CO2 injection. A pilot CO2 injection in Decatur, Illinois, was undertaken, with the injection zone being the highly saline and heterogeneous Mt. Simon sandstone, in order to better understand the feasibility of full-scale sequestration process. This paper reports the results of an extensive study of the morphology of the sandstone and its heterogeneity, and simulation of single-phase and two-phase flow of CO2 and brine in the formation's three-dimensional images. As we demonstrate by extensive analysis, the formation is much more heterogeneous than the typical sandstone, such as Berea sandstone. In addition to characterizing the morphology of the sandstone and computing its important flow characteristics, an important goal of the study is to compare the accuracy and computational efficiency of three distinct simulation approaches, namely, the lattice-Boltzmann (LB) approach, direct numerical simulation (DNS) of the governing equations of fluid flow that uses the finite-volume method coupled with the OpenFOAM simulator, and pore-network (PN) simulation. After validating the simulators by comparing the computed relative permeabilities that they produce for Berea sandstone, we simulate displacement of brine by CO2 at low and relatively high capillary numbers, and compute the relative permeabilities and other quantities of interest. We demonstrate that all the three methods provide consistent relative permeability-saturation functions that are in close agreement with one another. However, although the LB and DNS both produce similar relative permeabilities, the DNS approach is computationally more efficient because it simulates drainage by only a single set of computations over the entire saturation range, whereas the LB simulation requires separate simulation for each set saturation. Thus, the question of what method to use for simulating such flow processes at the scale of core plugs should mainly be addressed based on the computational time that one can afford and the computational resources that one has access to. Another important question addressed is the effect of the resolution of the computational grids or lattices used, particularly when one uses the LB method with voxelized images of porous media. We show that, unlike many claims in the past, one may need many lattice units per voxel in order to obtain reliable, lattice-independent results.

Oil recovery by low-salinity polymer flooding in carbonate oil reservoirs

Low-salinity polymer flooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect of combining the polymer injection and low-salinity water injection methods. To maximize EOR efficiency, it is essential to design the compositions of low-salinity water appropriately while considering polymer properties. The goal of this study was to investigate the effects of pH and potential determining ions (PDI; SO42− and Ca2+) in low-salinity polymer solution used as injection water on oil production when applying LSPF to a carbonate oil reservoir. From the experimental results, the SO42− ions interfered with polymer adsorption in the neutral SO42--containing polymer solution, while the adsorption was greatly promoted in the acidic conditions, reducing the permeability. In the Ca2+-containing polymer solution, the adsorption trend was different from the SO42− case. In examining the wettability alteration, the change in residual oil saturation between after-LSWF and after-LSPF (ΔSor) was greater with higher SO42− concentration under the neutral state. This means that the end-point of the relative permeability-saturation curves shifted to the right, indicating that wettability was altered to a more water-wet state. Under acidic conditions, ΔSor was smaller compared to the neutral state due to greater polymer adsorption. A small ΔSor was observed when Ca2+ ions were contained in the neutral polymer solution, causing less wettability alteration. This is because Ca2+ ions are involved in precipitation as well as adsorption, thus reducing the permeability more than SO42--containing case. We confirmed these changes also in the contact angle analysis. In conclusion, since SO42− ions interfered with adsorption of polymer molecules and adsorption occurred less in the neutral state, a neutral polymer solution with high SO42− ion concentration as an injection water provided the highest enhancement in the EOR efficiency.

Precise simulation of long-term DNAPL migration in heterogeneous porous media based on light transmission micro-tomography

Predicting long-term migration of dense non-aqueous phase liquids (DNAPLs) in subsurface systems is essential to determine appropriate remediation design for cleanup of subsurface contamination. The migration of DNAPLs is not only affected by the heterogeneity of porous media, but also controlled by the relative permeability of DNAPLs over long-term periods. A new light transmission micro-tomography (LTM) is developed to quantify the heterogeneity parameters including porosity, permeability and entry pressure of two dimensional (2D) porous media. Also, a relative permeability-saturation model (RPM) is proposed for the complexity of long-term DNAPLs migration in porous media, in which the infiltration and redistribution periods are simulated by the drainage and imbibition stages using Brooks and Corey (BC) model, respectively. To verify the effect of LTM and RPM, an experiment of long-term perchloroethylene (PCE) migration is performed in a 2D bench-scale sandbox and the simulation based on LTM and RPM is conducted to predict PCE migration behavior. Comparison and moment analysis of PCE plumes shows that PCE infiltration and spreading behavior is well modeled over long-term contaminant migration period including calibration, verification and validation periods. This reveals the complexity of DNAPL behavior and steps forward to accurately quantify micro-structures of porous media.

Single- and two-phase flow simulation based on equivalent pore network extracted from micro-CT images of sandstone core.

Due to the intricate structure of porous rocks, relationships between porosity or saturation and petrophysical transport properties classically used for reservoir evaluation and recovery strategies are either very complex or nonexistent. Thus, the pore network model extracted from the natural porous media is emphasized as a breakthrough to predict the fluid transport properties in the complex micro pore structure. This paper presents a modified method of extracting the equivalent pore network model from the three-dimensional micro computed tomography images based on the maximum ball algorithm. The partition of pore and throat are improved to avoid tremendous memory usage when extracting the equivalent pore network model. The porosity calculated by the extracted pore network model agrees well with the original sandstone sample. Instead of the Poiseuille’s law used in the original work, the Lattice-Boltzmann method is employed to simulate the single- and two- phase flow in the extracted pore network. Good agreements are acquired on relative permeability saturation curves of the simulation against the experiment results.

Application of continuum percolation theory for modeling single- and two-phase characteristics of anisotropic carbon paper gas diffusion layers

Percolation theory is used to model intrinsic and relative permeabilities as well as tortuosity in anisotropic carbon paper gas diffusion layers (GDL) and compared with existing results from lattice-Boltzmann (LB) simulations and experimental measurements. Although single- and two-phase characteristics of the carbon paper GDL are mainly affected by medium geometrical and topological properties, e.g., pore-size distribution, connectivity, and pore geometry, analyzing capillary pressure curves implies that the pore-size distribution of the carbon paper GDL is very narrow. This suggests that its effect on tortuosity and wetting- and nonwetting-phase relative permeabilities is trivial. However, integrated effects of pore geometry, surface area, connectivity, and tortuosity on intrinsic permeability might be substantial. Universal power laws from percolation theory predict the tortuosity-porosity and relative permeability–saturation curves accurately, indicating both characteristics not affected by the pore-size distribution. The permeability–porosity relationship, however, conforms to nonuniversality.

Comparison of relative permeability–saturation–capillary pressure models for simulation of reservoir CO2 injection

Constitutive relations between relative permeability (kr), fluid saturation (S), and capillary pressure (Pc) determine to a large extent the distribution of brine and supercritical CO2 (scCO2) during subsurface injection operations. Published numerical multiphase simulations for brine–scCO2 systems so far have primarily used four kr−S−Pc models. For the S−Pc relations, either the Brooks–Corey (BC) or Van Genuchten (VG) equations are used. The kr−S relations are based on Mualem, Burdine, or Corey equations without the consideration of experimental data. Recently, two additional models have been proposed where the kr−S relations are obtained by fitting to experimental data using either an endpoint power law or a modified Corey approach. The six models were tested using data from four well-characterized sandstones (Berea, Paaratte, Tuscaloosa, Mt. Simon) for two radial injection test cases. The results show a large variation in plume extent and saturation distribution for each of the sandstones, depending on the used model. The VG–Mualem model predicts plumes that are considerably larger than for the other models due to the overestimation of the gas relative permeability. The predicted plume sizes are the smallest for the VG–Corey model due to the underestimation of the aqueous phase relative permeability. Of the four models that do not use fits to experimental relative permeability data, the hybrid model with Mualem aqueous phase and Corey gas phase relative permeabilities provide the best fits to the experimental data and produce results close to the model with fits to the capillary pressure and relative permeability data. The model with the endpoint power law resulted in very low, uniform gas saturations outside the dry-out zone for the Tuscaloosa sandstone, as the result of a rapidly declining aqueous phase relative permeability. This observed behavior illustrates the need to obtain reliable relative permeability relations for a potential reservoir, beyond permeability and porosity data.

Effects of liquid layers and distribution patterns on three-phase saturation and relative permeability relationships: a micromodel study.

In the current study, we used micromodel experiments to study three-phase fluid flow in porous media. In contrast to previous studies, we simultaneously observed and measured pore-scale fluid behavior and three-phase constitutive relationships with digital image acquisition/analysis, fluid pressure control, and permeability assays. Our results showed that the fluid layers significantly influenced pore-scale, three-phase fluid displacement as well as water relative permeability. At low water saturation, water relative permeability not only depended on water saturation but also on the distributions of air and diesel. The results also indicate that the relative permeability-saturation model proposed by Parker et al. (1987) could not completely describe the experimental data from our three-phase flow experiments because these models ignore the effects of phase distribution. A simple bundle-of-tubes model shows that the water relative permeability was proportional to the number of apparently continuous water paths before the critical stage in which no apparently continuous water flow path could be found. Our findings constitute additional information about the essential constitutive relationships involved in both the understanding and the modeling of three-phase flows in porous media.

Pore network modeling of drainage process in patterned porous media: A quasi-static study

This work represents a preliminary investigation on the role of wettability conditions on the flow of a two-phase system in porous media. Since such effects have been lumped implicitly in relative permeability–saturation and capillary pressure–saturation relationships, it is quite challenging to isolate its effects explicitly in real porous media applications. However, within the framework of pore network models, it is easy to highlight the effects of wettability conditions on the transport of two-phase systems. We employ quasi-static investigation in which the system undergoes slow movement based on slight increment of the imposed pressure. Several numerical experiments of the drainage process are conducted to displace a wetting fluid with a non-wetting one. In all these experiments the network is assigned different scenarios of various wettability patterns. The aim is to show that the drainage process is very much affected by the imposed pattern of wettability. The wettability conditions are imposed by assigning the value of contact angle to each pore throat according to predefined patterns.

Identification of influential parameters through sensitivity analysis of the TOUGH + Hydrate model using LH-OAT sampling

The over-parameterisation, as a common issue in numerical models, may be unavoidable in the TOUGH + Hydrate (T + H) model. Therefore, a global sensitivity analysis of the influence of main or uneasily-measured 26 input parameters on five model outputs, i.e. cumulative gas production, gas production rate, hydrate saturation, gas saturation and aqueous saturation, under depressurization and brine-inhibitor injection was performed using the LH-OAT sampling method. The 26 parameters were classified as ‘Very important’, ‘Important’, ‘Slightly important’, and ‘Unimportant’ by analyzing their sensitivity indices at different sampling times and sampling positions in the modeling area, using the TSPAC segmentation package. The sensitivity of an input parameter to a model output was dependent on sampling time, sampling position and the identity of the model output in question. Cumulative gas production and gas production rate were governed by four permeability-related parameters (parameter n and residual aqueous saturation (in the relative permeability-saturation model), permeability reduction exponent and critical mobile phase saturation) and four inhibitor-related parameters (inhibitor density, the specific enthalpy of the dissolution of the inhibitor in water, reference inhibitor mole fraction in the aqueous phase and inhibitor-induced reference temperature depression). Hydrate saturation was governed by two hydrate dissociation-related parameters (temperature-dependent hydrate specific heat and hydrate density) and two parameters related to the flow of released fluids in the pore network (permeability and pore structure expansion). Gas saturation was governed by several types of input parameters: six parameters related to the flow of pore gas (parameter n and residual aqueous saturation (in the relative permeability-saturation model), critical mobile phase saturation, intrinsic permeability, permeability reduction exponent and pore compressibility), three inhibitor-related parameters (the specific enthalpy of the dissolution of the inhibitor in water, reference inhibitor mole fraction in the aqueous phase and inhibitor-induced reference temperature depression) and two hydrate dissociation-related parameters (temperature-dependent hydrate density polynomial and temperature-dependent hydrate specific heat polynomial). Finally, aqueous saturation was governed by five permeability-related parameters (parameter λ and residual aqueous saturation (in the saturation-capillary pressure function model), pore expansion, grain specific heat and the tortuosity factor model). Overall, the most influential parameter for all five model outputs was the parameter n in the relative permeability-saturation function model.

Numerical simulations of a light nonaqueous phase liquid (LNAPL) movement in variably saturated soils with capillary hysteresis

The fate and transport of pollutants in the subsurface is usually predicted using numerical simulations. Comparisons of the simulation results with experimental data are required to validate the numerical codes. In this paper, the nonaqueous phase liquid (NAPL) simulator code was used to numerically simulate two centrifugal light nonaqueous phase liquid (LNAPL) transport experiments. The numerical predictions were compared with the centrifugal test results and the impact of capillary hysteresis was evaluated. It was concluded that the simulation with the nonhysteretic model slightly underestimated the LNAPL volume retained in the vadose zone, and the average error of the predicted LNAPL saturation in the vadose zone and along the plume centerline was approximately 5% to 10%. The application of capillary hysteresis for the numerical simulation of the second centrifuge test has eliminated this error. In addition, accounting for hysteresis in the numerical simulation of the second centrifuge test has considerably improved the predicted results with respect to the size of the lens-shaped plume within the capillary fringe. However, there were inconsistencies between the numerical and experimental results, especially with respect to the time for the LNAPL to reach the groundwater level. This was found to be due to overestimation of the simulated downward infiltration of the LNAPL in the capillary fringe. It was found that the pore-connectivity parameter with a value of 0.66 for the relative permeability–saturation model produced the best comparison with experimental results.

Effect of residual oil saturation on hydrodynamic properties of porous media

To understand the effect of residual oil on hydraulic properties and solute dispersive behavior of porous media, miscible displacement column experiments were conducted using two petroleum products (diesel and engine oil) and a sandy soil. The effective water permeability, effective water-filled porosity, and dispersivity were investigated in two-fluid systems of water and oil as a function of residual oil saturation (ROS). At the end of each experiment, the distribution of ending ROS along the sand column was determined by the method of petroleum ether extraction-ultraviolet spectrophotometry. Darcy’s Law was used to determine permeability, while breakthrough curves (BTCs) of a tracer, Cl−, were used to calibrate effective porosity and dispersivity. The experimental results indicate that the maximum saturated zone residual saturation of diesel and engine oil in this study are 16.0% and 45.7%, respectively. Cl− is found to have no sorption on the solid matrix. Generated BTCs are sigmoid in shape with no evidence of tailing. The effective porosity of sand is inversely proportional to ROS. For the same level of ROS, the magnitude of reduction in effective porosity by diesel is close to that by engine oil. The relative permeability of sand to water saturation decreases with increasing amount of trapped oil, and the slope of the relative permeability–saturation curve for water is larger at higher water saturations, indicating that oil first occupies larger pores, which have the most contribution to the conductivity of the water. In addition, the reduction rate of relative permeability by diesel is greater than that by engine oil. The dispersivity increases with increasing ROS, suggesting that the blockage of pore spaces by immobile oil globules may enhance local velocity variations and increase the tortuosity of aqueous-phase flow paths.