Trapping Of Nonwetting Phase Research Articles

Image-based modeling of spontaneous imbibition in porous media by a dynamic pore network model

The dynamic pore-network modeling, as an efficient pore-scale tool, has been used to understand imbibition in porous media, which plays an important role in many subsurface applications. In this work, we aim to develop a dynamic pore-network model for imaged-based modeling of spontaneous imbibition in porous media. The µCT scanning of a porous medium of sintered glass beads is selected as our study domain. We extract its pore network by using an open-source software of PoreSpy, and further project the extracted information of individual watersheds into multiform idealized pore elements. A number of case studies of primary spontaneous imbibition have been conducted by using both the pore-network model and a VOF model, under different wettability values and viscosity ratios. We compare those model predictions in terms of imbibition rates and temporal saturation profiles along the flow direction. We show that our pore-network model can well predict imbibition rates and temporal saturation profiles under different viscosity ratios and wetting conditions, in comparison to the VOF model. We explore the effect of viscosity ratio on the trapping of nonwetting phase. Moreover, we discuss the difference between spontaneous imbibition and quasi-static imbibition in terms of pore-filling mechanisms.

Capillary Trapping Following Imbibition in Porous Media: Microfluidic Quantification of the Impact of Pore‐Scale Surface Roughness

AbstractDue to diagenesis, pores in subsurface rocks such as sandstones exhibit varying degrees of surface roughness in the forms of authigenic cement coatings and mineral dissolution. Previous work describing capillary trapping in porous media has primarily focused on pore‐space geometry, wettability, and fluid viscosity contrast, while acknowledging, but not quantifying, the potential impact of surface roughness. We introduce a method to implement surface roughness with controlled variation of hillock density and heights into glass microfluidic chips and investigate surface roughness impacts on gas trapping following imbibition of water into air. We demonstrate that surface roughness with hillock height‐to‐pore‐depth ratios (herein called Ω) less than a media‐dependent threshold (Ω = 6%–10% in the micromodels) does not promote nonwetting phase (gas) trapping. By contrast, rougher micromodels with Ω values larger than the aforementioned roughness threshold show a dramatic increase in the saturation of trapped gas (gas saturation values up to 64%) due to an observed change in imbibition dynamics from binary filling to pendular‐ring formation within pore throats as well as capillary pinning within pore bodies. Furthermore, when the micromodel intermediate capillary number results are compared to Land's model, only the roughest microfluidics chips (Ω > 10%) fall within the literature‐described values of the characteristic trapping constant, C, implying that surface roughness is also a key gas trapping control, independent of or in addition to pore‐space geometry and wettability. An a priori menisci stability criterion and a heuristic explanation based on local contact angle variations are proposed to explain surface roughness‐induced trapping.

Defining a novel pore-body to pore-throat “Morphological Aspect Ratio” that scales with residual non-wetting phase capillary trapping in porous media

Abstract We introduce a new method for defining a pore-body to pore-throat aspect ratio from segmented 3D image data, based on a connectivity metric applicable to porous media with widely varying pore-space connectivity and pore-space morphology. The ‘Morphological Aspect Ratio’ (MAR) is identified from the pore-space connectivity, using the Euler number (χ) as a function of a pore-space size defined by a morphological opening (erosion and dilation) of the pore space. We show that residual non-wetting phase trapping in porous media resulting from secondary imbibition scales with the MAR. Trapping was investigated in a Bentheimer sandstone core and five columns of partially sintered glass-particle packs with different combinations of glass beads and crushed glass ranging in size from 0.3 to 1.2 mm, resulting in porosity levels of 22–36%. Residual non-wetting phase trapping scales with the MAR, in contrast to the aspect ratio calculated with the traditional Maximum Inscribed Sphere (MIS) algorithm applied after partitioning the pore space into pore bodies and pore throats with a watershed transform followed by a region merging algorithm. This novel aspect ratio is a robust method that is less affected by segmentation errors compared to other methods for calculating aspect ratio and is applicable to residual non-wetting phase trapping resulting from capillary-driven flow of a wetting fluid through water-wet porous media.

Proppant-packed fractures in shale gas reservoirs: An in-situ investigation of deformation, wettability, and multiphase flow effects

The results of a systematic, micro-scale experimental investigation on two-phase gas/brine flow through proppant-packed fractured shale samples under increasing effective stresses of up to 5000 psi are presented in this paper. We use a miniature core-flooding apparatus integrated with a high-resolution X-ray micro-CT scanner to perform the flow experiments. Geomechanical deformation and its impact on displacement mechanisms governing fluid transport within the packed fractures are studied at the pore scale under certain flow and stress conditions. These conditions were carefully designed to represent reservoir depletion and transport of water through such media. Since proppant grains are placed to maintain the long-term conductivity of the induced fractures, they significantly influence the geomechanical and multi-phase flow behavior of these conduits during reservoir depletion. We particularly examined the effectiveness of modified resin-coated sand (compared to a basic white sand) in maintaining the hydraulic conductivity of induced fractures. Significant bullet-like embedment and proppant crushing under severe stress conditions were found to be the shortcomings of these proppants, respectively. We then developed a methodical framework to design improved proppants with a similar mechanical strength to the host shale rock to withstand these drawbacks.Sphericity, roundness, and size of the proppant grains also impacted the critical properties of the constructed pore space such as pore size distribution and pore-throat aspect ratio. Such parameters control pore-scale gas-to-brine and brine-to-gas displacements within the hydraulic fractures. We specifically studied the non-wetting phase trapping and its subsequent impact on reduction of available pore space for other fluids to flow. It was found that trapped gas globules are very likely to deform within the medium and redistribute/reconnect under a higher effective stress. For the first time, wettability alteration of the proppant pack from water-wet to oil-wet was observed in a gas/brine fluid system. Wettability alteration occurred non-uniformly and was thought to be due to deposition of the shale organic matter released after significant proppant embedment. Such wetting characteristics aggravate multi-phase trapping within the fractures, which in turn leads to dramatic reductions in effective gas permeability. This study is concluded with a set of recommendations that can be used to effectively maintain the productivity of propped fractures for extended period of time.

Droplet Imbibition into Paper Coating Layer: Pore-Network Modeling Simulation

Liquid penetration into thin porous media such as paper is often simulated using continuum-scale single-phase Darcy’s law. The underlying assumption was that a sharp invasion front percolates through the layer. To explore this ambiguous assumption and to understand the controlling pore-scale mechanisms, we have developed a dynamic pore-network model to simulate imbibition of a wetting phase from a droplet into a paper coating layer. The realistic pore structures are obtained using the FIB-SEM imaging of the coating material with a minimum resolution of 3.5 nm. Pore network was extracted from FIB-SEM images using Avizo software. Data of extracted pore network are used for statistically generating pore network. Droplet sizes are chosen in the range of those applicable in inkjet printing. Our simulations show no sharp invasion front exists and there is the presence of residual non-wetting phase. In addition, penetration of different sizes of droplets of different material properties into the pore network with different pore body and pore throat sizes are performed. We have found an approximately linear decrease in droplet volume with time. This contradicts the expected sqrt{t}-behavior in vertical imbibition that is obtained using macroscopic single-phase Darcy’s law. With increase in flow rate, transition of imbibition invasion front from percolation-like pattern to a more sharper one with less trapping of non-wetting phase is also reported. Our simulations suggest that the single-phase Darcy’s law does not adequately describe liquid penetration into materials such as paper coating layer. Instead Richards equation would be a better choice.

Imaging and quantification of spreading and trapping of carbon dioxide in saline aquifers using meter‐scale laboratory experiments

AbstractThe role of capillary forces during buoyant migration of CO2 is critical toward plume immobilization within the postinjection phase of a geological carbon sequestration operation. However, the inherent heterogeneity of the subsurface makes it very challenging to evaluate the effects of capillary forces on the storage capacity of these formations and to assess in situ plume evolution. To overcome the lack of accurate and continuous observations at the field scale and to mimic vertical migration and entrapment of realistic CO2 plumes in the presence of a background hydraulic gradient, we conducted two unique long‐term experiments in a 2.44 m × 0.5 m tank. X‐ray attenuation allowed measuring the evolution of a CO2‐surrogate fluid saturation, thus providing direct insight into capillarity‐dominated and buoyancy‐dominated flow processes occurring under successive drainage and imbibition conditions. The comparison of saturation distributions between two experimental campaigns suggests that layered‐type heterogeneity plays an important role on nonwetting phase (NWP) migration and trapping, because it leads to (i) longer displacement times (3.6 months versus 24 days) to reach stable trapping conditions, (ii) limited vertical migration of the plume (with center of mass at 39% versus 55% of aquifer thickness), and (iii) immobilization of a larger fraction of injected NWP mass (67.2% versus 51.5% of injected volume) as compared to the homogenous scenario. While these observations confirm once more the role of geological heterogeneity in controlling buoyant flows in the subsurface, they also highlight the importance of characterizing it at scales that are below seismic resolution (1–10 m).

Petrophysical characterization of porous media starting from micro-tomographic images

A quasi-static scheme based on pore space spatial statistics is presented to simulate pore-scale two-phase capillary-dominant displacement processes. The algorithm is coupled with computational fluid dynamics in order to evaluate saturation functions. Wettability heterogeneity in partial and fractional/mixed-wet media is implemented using a contact angle map. The simulation process is pixel-wised and performed directly on binary images. Bypassing and snap-off are tackled as non-wetting phase trapping mechanisms. Post-processing results include residual saturations, effective permeability and capillary pressure curves for drainage and imbibition scenarios. The primary advantages of the proposed workflow are eliminating pore space skeletisation/ discretization, superior time efficiency and minimal numerical drawbacks when compared to other direct or network-based simulation techniques.

Impact of wettability alteration on 3D nonwetting phase trapping and transport

We investigate capillary trapping and fluid migration via x-ray computed microtomography (x-ray CMT) of nonwetting phase (air) and wetting phase (brine) in Bentheimer sandstone cores which have been treated to exhibit different degrees of uniform wettability. x-Ray CMT scans were acquired at multiple steps during drainage and imbibition processes, as well as at the endpoints; allowing for assessment of the impact of wettability on nonwetting phase saturation and cluster size distribution, connectivity, topology and efficiency of trapping. Compared with untreated (water-wet) Bentheimer sandstone, cores treated with tetramethoxylsilane (TMS) were rendered weakly water-wet, and cores treated with octadecyltrichlorosilane (OTS) demonstrate intermediate-wet characteristics. As apparent contact angle increases, drainage flow patterns deviate from those derived for water-wet systems, total residual trapping and trapping efficiency decrease, and buoyancy plays a larger role during nonwetting phase mobilization; this has significant implications for CO2 migration and trapping during CO2 sequestration operations.

The impact of pore structure and surface roughness on capillary trapping for 2‐D and 3‐D porous media: Comparison with percolation theory

AbstractWe study the impact of pore structure and surface roughness on capillary trapping of nonwetting gas phase during imbibition with water for capillary numbers between 10−7 and 5 × 10−5, within glass beads, natural sands, glass beads monolayers, and 2‐D micromodels. The materials exhibit different roughness of the pore‐solid interface. We found that glass beads and natural sands, which exhibit nearly the same grain size distribution, pore size distribution, and connectivity, showed a significant difference of the trapped gas phase of about 15%. This difference can be explained by the microstructure of the pore‐solid interface. Based on the visualization of the trapping dynamics within glass beads monolayers and 2‐D micromodels, we could show that bypass trapping controls the trapping process in glass beads monolayers, while snap‐off trapping controls the trapping process in 2‐D micromodels. We conclude that these different trapping processes are the reason for the different trapping efficiency, when comparing glass beads packs with natural sand packs. Moreover, for small capillary numbers of 10−6, we found that the cluster size distribution of trapped gas clusters of all 2‐D and 3‐D porous media can be described by a universal power law behavior predicted from percolation theory. This cannot be expected a priori for 2‐D porous media, because bicontinuity of the two bulk phases is violated. Obviously, bicontinuity holds for the thin‐film water phase and the bulk gas phase. The snap‐off trapping process leads to ordinary bond percolation in front of the advancing bulk water phase and is the reason for the observed universal power law behavior in 2‐D micromodels with rough surfaces.

Experimental characterization of nonwetting phase trapping and implications for geologic CO2 sequestration

Geological carbon sequestration is being considered worldwide as a means of mitigating anthropogenic emission of greenhouse gases. During sequestration, carbon dioxide (CO2) gas effluent is captured from coal-fired power plants or other concentrated emission sources and injected into saline aquifers or depleted oil reservoirs for long term storage. In an effort to fully understand and optimize CO2 trapping efficiency, the capillary mechanisms that immobilize subsurface CO2 were analyzed at the pore-scale. Pairs of proxy fluids representing the potential range of in-situ conditions of supercritical CO2 (nonwetting fluid) and brine (wetting fluid) were used during experimentation. The two fluids were imbibed and drained from a flow cell apparatus containing a sintered glass bead core. Fluid parameters (such as interfacial tension and fluid viscosities) and flow rate were altered to characterize their relative impact on capillary trapping. Computed x-ray microtomography (microCT) was used to quantify immobilized nonwetting fluid volumes after imbibition and drainage events. MicroCT-analyzed data suggests that capillary trapping in sintered glass bead (a mildly consolidated porous medium) is dictated by the capillary number (Ca), the viscosity ratio (M), and the Bond number (Bo) of the system, reflecting that all three viscous, capillary, and gravity forces affect the displacement process to varying degree as their relative importance changes. The amount of residual trapped nonwetting phase was observed to increase with increasing nonwetting fluid viscosity, and with decreasing density difference of the fluids; this suggests that CO2 sequestration can potentially be engineered for optimal trapping through alterations to the viscosity or density of supercritical CO2.

Efficiently engineering pore-scale processes: The role of force dominance and topology during nonwetting phase trapping in porous media

We investigate trapping of a nonwetting (NW) phase, air, within Bentheimer sandstone cores during drainage–imbibition flow experiments, as quantified on a three dimensional (3D) pore-scale basis via x-ray computed microtomography (X-ray CMT). The wetting (W) fluid in these experiments was deionized water doped with potassium iodide (1:6 by weight). We interpret these experiments based on the capillary–viscosity–gravity force dominance exhibited by the Bentheimer–air–brine system and compare to a wide range of previous drainage–imbibition experiments in different media and with different fluids. From this analysis, we conclude that viscous and capillary forces dominate in the Bentheimer–air–brine system as well as in the Bentheimer–supercritical CO2–brine system. In addition, we further develop the relationship between initial (post-drainage) NW phase connectivity and residual (post-imbibition) trapped NW phase saturation, while also taking into account initial NW phase saturation and imbibition capillary number. We quantify NW phase connectivity via a topological measure as well as by a statistical percolation metric. These metrics are evaluated for their utility and appropriateness in quantifying NW phase connectivity within porous media. Here, we find that there is a linear relationship between initial NW phase connectivity (as quantified by the normalized Euler number, χˆ) and capillary trapping efficiency; for a given imbibition capillary number, capillary trapping efficiency (residual NW phase saturation normalized by initial NW phase saturation) can decrease by up to 60% as initial NW phase connectivity increases from low connectivity (χˆ≈0) to very high connectivity (χˆ≈1). We propose that multiphase fluid-porous medium systems can be efficiently engineered to achieve a desired residual state (optimal NW phase saturation) by considering the dominant forces at play in the system along with the impacts of NW phase topology within the porous media, and we illustrate these concepts by considering supercritical CO2 sequestration scenarios.

Phase Trapping Effects in Viscous-modified Low Interfacial Tension Flow during Surfactant-polymer Flooding in Heavy Oil Reservoirs

This study examines the effects of non-wetting phase trapping in viscous-modified low-interfacial tension flow during viscous surfactant waterflooding (or surfactant-polymer flooding) under three different injection flowrates in three initially preferential water-wet porous media (each with a different pore throat size) partially filled with heavy oil and brine. In two approaches developed in this study, dynamic mean pore-scale capillary number Nc1 is considered as the foremost criterion to characterize the effect of non-wetting phase trapping. In the first approach, which is a pore network approach, the effect of phase trapping on the value of Nc1 is neglected. In the second approach, which is a numerical method, the effect of phase trapping is included. By comparing the values of Nc1 from the pore network approach and numerical method, the effect of phase trapping is characterized. The change in Nc1 was found to be an appropriate tool to characterize the effects of phase trapping in viscous surfactant waterflooding.

Hysteretic trapping and relative permeability of CO2 in sandstone at reservoir conditions

Hysteretic nonwetting phase trapping behavior is predicted to be a significant factor determining long term immobilization of injected CO2. This paper presents results from an experimental investigation of hysteresis in residual trapping and relative permeability of CO2 in a CO2/water system at 50°C and 9MPa in a Berea sandstone core. Carbon dioxide saturation data were collected using the steady-state method in a horizontal core-flooding apparatus with X-ray computed tomography. Three flooding cycles were completed at a constant total volumetric flow rate by incrementally increasing and decreasing the fractional flow rates of supercritical CO2 and water. The fractional flow rates were chosen such that the maximum CO2 saturation of each cycle was greater than that of the previous cycle. During the injection stage of a cycle, CO2 displaced water in a wetting-phase drainage process (water saturation decrease). Following injection, water displaced CO2 in a wetting-phase imbibition process (water saturation increase). The fractional flow of CO2 was then increased during the next cycle. Results showed the CO2 saturations trapped during wetting-phase imbibition increased with the maximum CO2 saturations reached during each cycle. The residually trapped CO2 saturation is a hysteretic function, depending on the maximum saturation reached by the core before imbibition. A linear model with coefficient 0.5 describes the nonwetting trapping relationship. The experimental relative permeability data for CO2 fit a single bounding primary drainage curve while CO2 saturations increased, but followed three different scanning curves during wetting-phase imbibition. The CO2 relative permeability data can be fit by making a minor modification in the Van Genuchten–Burdine relative permeability data to account for hysteresis.

Effect of fluid topology on residual nonwetting phase trapping: Implications for geologic CO2 sequestration

This work examines the influence of initial (i.e. post drainage) nonwetting (NW) fluid topology on total residual (i.e. after imbibition) NW phase saturation. Brine and air (used as a proxy for supercritical CO2) flow experiments were performed on Bentheimer sandstone; results were quantified via imaging with X-ray computed microtomography (X-ray CMT), which allows for three dimensional, non-destructive, pore-scale analysis of the amount, distribution, and connectivity of NW phase fluid within the sandstone cores. In order to investigate the phenomenon of fluid connectivity and how it changes throughout flow processes, the Bentheimer sandstone results are compared to previously collected X-ray CMT data from similar experiments performed in a sintered glass bead column, a loose packed glass bead column, and a column packed with crushed tuff. This allows us to interpret the results in a broader sense from the work, and draw conclusions of a more general nature because they are not based on a single pore geometry. Connectivity is quantified via the normalized Euler number of the NW fluid phase; the Euler number of a particular sample is normalized by the maximum connectivity of the media, i.e. the Euler number of the system at 100% NW phase saturation. General connectivity-saturation relationships were identified for the various media. In terms of trapping, it was found that residual NW phase trapping is dependent on initial (i.e. post-drainage) NW phase connectivity as well as imbibition capillary number for the Bentheimer sandstone. Conversely, the sintered glass bead column exhibited no significant relationship between trapping and NW topology.These findings imply that for a CO2 sequestration scenario, capillary trapping is controlled by both the imbibition capillary number and the initial NW phase connectivity: as capillary number increases, and the normalized initial Euler number approaches a value of 1.0, capillary trapping is suppressed. This finding is significant to CO2 sequestration, because both the drainage (CO2 injection) and imbibition (subsequent water injection or infiltration) processes can be engineered in order to maximize residual trapping within the porous medium. Based on the findings presented here, we suggest that both the Euler number-saturation and the capillary number-saturation relationships for a given medium should be considered when designing a CO2 sequestration scenario.

Relative Permeability Hysteresis: Water-Alternating-Gas Injection and Gas Storage

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 161827, ’Experimental and Theoretical Investigation of Water/Gas Relative Permeability Hysteresis: Applicable to Water-Alternating-Gas (WAG) Injection and Gas-Storage Processes,’ by S. Mobeen Fatemi, SPE, and Mehran Sohrabi, SPE, Heriot-Watt University, prepared for the 2012 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Accurate determination of relative permeability hysteresis is needed to predict water-alternating-gas (WAG) injection reliably. Two series of gas/water relative permeability hysteresis curves were obtained from corefloods under mixed-wet conditions. The results revealed that none of the widely used hysteresis models (e.g., Carlson and Killough models) is able to predict the observed cyclic relative permeability hysteresis for alternating injection of gas and water. The results suggest that, for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for modeling both the wetting and the nonwetting phase. Introduction Because of nonwetting-phase trapping, wetting-phase relative permeability for imbibition increased compared with the drainage case and nonwetting-phase imbibition relative permeability was less than that of the drainage case. Therefore, relative permeability to a fluid at a given saturation depends on whether that saturation was obtained by approaching it from a higher or lower value. This behavior in relative permeability is the hysteresis effect. Much of the hysteresis data in the literature was obtained with saturations starting at endpoint values (i.e., irreducible-water saturation or residual-oil saturations for a water/oil system). These data usually deal with the differences between bounding relative permeabilities. Such data are more applicable to modeling reservoir processes in which phase saturations increase or decrease to an intermediate value, then change in the opposite direction. Examples include enhanced-oil-recovery methods such as WAG injection or cyclic-steam stimulation. Most of the existing relative permeability hysteresis functions were developed for strongly water-wet porous media. However, it generally is accepted that many oil reservoirs are mixed-wet. In a mixed-wet system, the oil-wet pores correspond to the largest pores in the rock, while the small pores are water-wet. There are only a few relative permeability models developed for mixed-wet porous media, of which none are included in commercial simulators. The purpose of this study was to further investigate the effect of cyclic hysteresis for water/gas systems under mixed-wet conditions. These two-phase relative permeability data are of interest for reliable simulation of processes involving cyclic changes between imbibition and drainage displacement, including WAG injection. The results of this study can be applied to underground hydrocarbon-gas storage, which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on an annual basis. This is especially true if the underground formation has an active aquifer.

Heterogeneity effect on non-wetting phase trapping in strong water drive gas reservoirs

In strong water drive gas reservoirs (WDGR), the presence of entrance water in the gas zone has negative effects on the relative permeability; therefore, gas is trapped behind the water front as a non-wetting phase. Understanding WDGR could be complicated and depends on both the petrophysical and operational parameters, such as, reservoir heterogeneity, permeability, production rate and so on. In order to quantify the uncertainty associated with reservoirs, it is critical to create porous media models that incorporate stratigraphic details.In the present study, experimental models were used to simulate WDGR and describe the heterogeneity effect on residual gas saturation and the recovery factor. In models, distinct gas and water (aquifer portion) zones were designed, wherein the ratio of the permeability of the aquifer to the gas zone was varied over three ranges. All tests were conducted in the presence of connate water, and the main WDGR set-up was constructed for high pressure operational conditions. All porous media were characterized by Dykstra–Parsons coefficient as heterogeneity index.The results demonstrate that the residual gas saturation depends on both heterogeneity index and permeability ratio. Results reveal that heterogeneity is not always detrimental to gas recovery. In addition, when the ratio of the aquifer to gas zone permeability is less than one, the amount of trapped gas reduces as the heterogeneity of the porous media increases and consequently, the recovery factor may be improved.

Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well

Summary We used a commercial reservoir simulator to study, first, the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure and, second, the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account by the use of the Carlson model, with the various bounding drainage and imbibition curves computed from a pore network model. Filtrate invasion into a hydrocarbon formation influences the readings of well-logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behavior of invasion around observation wells where no flow in or out of the formation occurs after completion, and with regard to the influence of formation wettability. We find that after sufficient time, the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil/mixed-wet case. Nonwetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the endpoints of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil/mixed-wet case. The simulation results allow us to understand how logging-tool measurements made in cased observation wells are influenced by drilling-fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and the persistence of invaded zone saturation and between invaded zone saturation and the distortion of subsequent flood fronts.

Trapping of the non-wetting phase in an interacting triangular tube bundle model

An interacting triangular tube bundle model is developed using capillaries of equilateral triangle cross sections. In addition to pressure equilibration among the capillaries, the non-circular tubes allow the wetting phase to reside in the corners and flow continuously in the entire model. An interacting-serial type model is constructed with step changes of tube size along the model, while the total cross-section of the model is kept constant. This model includes trapping of oil which is absent in traditional tube bundle models. Trapping of non-wetting phase in the model in imbibition processes is simulated. The relationship between the residual oil saturation and the complete capillary number CA is investigated. The simulation results obtained by this model are consistent with the results reported in literature of both experimental studies, using actual porous media, and simulations in pore-scale network models. The effects of the tube size, tube size distribution and viscosity ratio on the magnitude of entrapment are also studied using this tube bundle model.

Two-Phase Flow in Heterogeneous Porous Media with Non-Wetting Phase Trapping

This article presents a mathematical model describing flow of two fluid phases in a heterogeneous porous medium. The medium contains disconnected inclusions embedded in the background material. The background material is characterized by higher value of the non-wetting-phase entry pressure than the inclusions, which causes non-standard behavior of the medium at the macroscopic scale. During the displacement of the non-wetting fluid by the wetting one, some portions of the non-wetting fluid become trapped in the inclusions. On the other hand, if the medium is initially saturated with the wetting phase, it starts to drain only after the capillary pressure exceeds the entry pressure of the background material. These effects cannot be represented by standard upscaling approaches based on the assumption of local equilibrium of the capillary pressure. We propose a relevant modification of the upscaled model obtained by asymptotic homogenization. The modification concerns the form of flow equations and the calculation of the effective hydraulic functions. This approach is illustrated with two numerical examples concerning oil–water and CO2–brine flow, respectively.

Measurements of non-wetting phase trapping applied to carbon dioxide storage

We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for CO 2 storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO 2 immobile. The CO 2 is injected into the formation followed by chase brine injection, or natural groundwater flow, which displaces and traps CO 2 on the pore scale as a residual immobile phase. Current models to predict the amount of trapping are based on experiments in consolidated media, while CO 2 may be stored in relatively shallow, poorly consolidated systems. We use analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation. This behaviour is not predicted by the traditional literature trapping models, but is physically consistent with unconsolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. A good match to our experimental data was achieved with the trapping model proposed by Aissaoui.