Capillary Threshold Pressure Research Articles

Threshold capillary pressure of caprocks for CO2 storage: Numerical insight on the dynamic and residual method

The dynamic threshold pressure method and the residual capillary pressure method provide an estimate of the threshold capillary pressure for CO2 storage. In the dynamic method, the threshold capillary pressure is determined by comparing the discharge measured when the CO2 starts flowing into the sample with the one measured when only water is flowing. In the residual method, a high CO2 pressure is applied on the vessel at the inlet of a water-saturated sample while water cannot flow from the vessel at its end. The threshold capillary pressure is estimated as the difference between the CO2 and the water pressures at the sample boundaries at equilibrium conditions.Sensitive analyses showed the impact of material properties and experimental conditions on results. Both methods allow estimating the threshold capillary pressure within a few days and the estimates are influenced by the applied pressures. The dynamic method estimate is not precautionary, and it tends to the exact value as the applied CO2 overpressure decreases. The residual method estimate is influenced by the drainage conditions and the volume of the vessels: it is generally precautionary and tends to increase with the volume of the vessels and the applied pressure. Suggestions for test interpretation and planning are also provided.

CO2 storage: threshold capillary pressure estimate in a remoulded caprock specimen

CO2 storage: threshold capillary pressure estimate in a remoulded caprock specimen

Simulation study of affecting parameters during low salinity water injection in carbonate reservoirs: from core to field scale

Over the last decade, economic and environmental factors have led to low salinity water injection (LSWI) becoming one of the most important improved oil recovery methods. Although many results have been obtained from laboratory tests, only a few papers have been published regarding the modeling and simulating LSWI in carbonate reservoirs compared to sandstone reservoirs. This paper investigated the most affecting parameters on oil recovery during LSWI at the core and field scale. The published work focused more on the effective parameters related to ultimate oil recovery using LSWI. However, important parameters affecting the oil recovery rate were not investigated. We compared how important parameters affected the ultimate oil recovery factor and ultimate oil recovery rate. According to the results of this study, the salinity of injected water and curvature of oil relative permeability were the most important factors on the ultimate oil recovery factor. By reducing both of these parameters, more increment oil was recovered. By increasing the injection rate of water, the curvature of the water relative permeability, wettability, and the endpoint of oil relative permeability, the oil recovery rate also increased. Furthermore, threshold capillary pressure and the endpoint of relative permeability of water had inverse effects on oil recovery. Injecting low salinity water into the reservoir will change its wettability. As a result, it will change the properties of the reservoir and increase the production from the reservoir, resulting in more oil being produced. LSWI resulted in an increase of oil recovery factor of 5% and 11% respectively after 25 and 58 years in this case.

Evaluating propensity for fugitive gas migration from integrity compromised oil and gas wells in the Peace Region, British Columbia, Canada, with a petrophysical approach

Oil and gas wells can suffer integrity failure resulting in the release of fugitive gas, formed primarily of methane, into the subsurface and atmosphere. Factors affecting fugitive gas migration in the subsurface, and in particular within and between shallower units intersected by energy wells (i.e. <100 m depth), are usually poorly considered with little focus on specific lithological characteristics that control gas movement, determine environmental impacts and influence how best to detect, monitor and quantify fugitive gases. To better understand and identify properties that can control fugitive gas migration in shallow sedimentary rocks that form the Peace Region of British Columbia, Canada, we developed a workflow by which a series of rock cores from units present in the area were obtained and their flow properties characterised. Insights on propensity for fugitive gas migration within and between these rocks were achieved through laboratory techniques and analytical calculations that are usually applied to the study of deeper hydrocarbon migration and seal integrity. These included Mercury Intrusion Porosimetry, petrographic analysis, X-ray computed tomography, as well as estimations of threshold capillary pressure, gas-column heights, hydrostatic pore pressure and total displacement pressure. Results show a congruent correlation between the examined petrophysical rock characteristics and flow propensity. We find that high capillary pressure will act as an effective mechanism for limiting vertical gas migration in the region, even when potential barrier facies have porosities of more than 10% and permeability of 0.26 mD. Additionally, results suggest that the propensity of studied shallow sediments to transmit fugitive gases will be controlled by heterogeneity, permeability anisotropy and the presence of secondary structural features, such as microfractures. Our approach for evaluating the propensity of fugitive gas migration could be applied elsewhere to enhance understanding of potential migration pathways and aid in development of effective monitoring and detection strategies that can better anticipate gas behaviour in the subsurface and prognosticate reactive transport, impacts and fate.

Dynamic analysis of small droplets at constant pressure and analytical model for drip systems and very low pressure drop-on-demand applications

We study the evolution of the growing volume of a droplet formed out of a capillary tube driven at a constant applied pressure by optical volume detection. A particular application aims at modeling the dynamic of the drop in the case of the injection of drugs in the middle-ear cavity using a small target drug delivery system. Various dispense tips such as a steel needle or silicone catheters and different t-BuOH aqueous solutions were used. A physical model based on the simplified Laplace–Young equation for a spherical droplet was developed to interpret the experimental results and model the observed deviation of the mean flow rate from the Poiseuille law when the drop radius is smaller than the capillary length. We emphasize the large influence of the surface tension which introduces a highly nonlinear effect at low applied pressure just above the capillary threshold pressure. The model fits well the evolution of the growing volume at various applied pressure up to a maximum diameter corresponding to the drop size close to the capillary length of the fluid, lc=γ/ρg, based on the liquid density ρ, gravity g and surface tension γ. We demonstrate that the model can also be applied to non spherical pendant droplets providing the apex elongation over the drop height of a spherical cap of the same volume is kept in a 30% range.

Representation of Fully Three‐Dimensional Interfacial Curvature in Pore‐Network Models

AbstractQuasi two‐dimensional approximations of interfacial curvature, present in current network models of multiphase flow in porous media, are extended to three dimensions. The new expressions for threshold capillary pressure are validated and calibrated using high‐resolution direct numerical simulations on synthetic geometries. The effects of pore‐space expansion and sagittal interface curvature on displacement are quantified, and are shown to be a key step in improving the physical accuracy of network models. Finally, the calibrated network model is used to obtain predictions for relative permeability and capillary pressure in a water‐wet Bentheimer sandstone. The predictions are compared to experimental measurements, revealing that the inclusion of three‐dimensional interfacial curvature leads to more accurate predictions.

A Data Science Approach to Uncertainty Evaluation in Fault-Seal Analysis for Exploration Applications in Siliciclastic Reservoirs

Summary Fault-seal analysis is used to understand the risk of hydrocarbons leaking out of a trap across bounding faults. There is a broad standard industry workflow for this analysis in clastic rocks, involving building a structural framework of the key seismic horizons and faults, estimating the clay content of the stratigraphy, predicting fault clay content using an algorithm such as shale gouge ratio (SGR), converting the predicted clay content to capillary threshold pressure, and calculating sealing capacity using the reservoir fluid properties. The inputs to the analysis are typically subject to considerable uncertainty that is difficult to understand and evaluate. One approach is to create “end member” scenarios to evaluate the impact of the key uncertainties, but this gives an incomplete picture and only a limited number of scenarios can be run and analyzed in the time typically available. The approach outlined here instead uses an automated workflow that runs hundreds of scenarios with stochastically varying input parameters. Data-science techniques combining domain expertise, mathematics and statistics, and computer coding are used to analyze and build models of the results. The advantages of the approach over a traditional fault-seal analysis workflow are that a wider range of input uncertainties can be considered, and that the results of a large number of realizations can be consolidated and visualized in ways that are specific to the problem being addressed and useful to the geologist undertaking the analysis. A key advantage is that the uncertainty inherent in this type of analysis can be explicitly incorporated, and the impact of the uncertainty clearly understood and communicated to decision-makers. Similar techniques could be applied to other geological analyses where uncertainty is an issue.

Micro-scale experimental investigation of the effect of pore space deformation on trapping of supercritical CO2

In this study, we investigate the impact of pore space deformation on various trapping mechanisms of supercritical CO2 (scCO2) relevant to storage of CO2 in deep saline aquifers. A series of unsteady-state two-phase brine/scCO2 drainage, imbibition, and dissolution tests were performed on a miniature sandpack sample under various stress conditions. High-resolution x-ray microtomography techniques were employed to acquire the pore and fluid occupancy maps at each step of the experiment, which were subsequently utilized to characterize the pore space deformation and changes in the frequencies of various pore-scale fluid displacement events. Our results revealed that, during the scCO2 injection stage, additional scCO2 was stored in the sandpack sample after the sandpack was compressed due to an increase in the pressure gradient even though the pore volume had decreased. On the other hand, the capillary trapping was impaired by the pore space contraction because all the imbibition displacement mechanisms at the pore scale, including the piston-like advance and snap-off, were facilitated as a consequence of an increase in their threshold capillary pressures. The increased frequency of snap-off events caused additional trapping, but more importantly, displaced scCO2 from throats by fragmenting large residual scCO2 clusters into smaller globules. During the dissolution process, the trapped scCO2 clusters and globules shrank in both pore bodies and throats, resulting in movement of the Main Terminal Meniscus (MTM) interfaces and snap-off events, respectively. The water relative permeability during the dissolution process decreased, at a fixed saturation, with the increase in the effective stress since the small pores occupied by the water phase deformed more significantly than the large pores.

Pore-Scale Study of Wettability Alteration and Fluid Flow in Propped Fractures of Ultra-Tight Carbonates

The in situ change in oil flow behavior inside propped fractures due to wettability alteration of proppant grains and fracture surfaces was thoroughly investigated for the first time in this study. A series of microscale flow experiments were performed in mixed-wet fractured and propped miniature ultra-tight carbonate cores where the effect of wettability on oil bridging and fracture oil layer integrity was probed during oil production. During the initial production, proppant wettability changed toward an intermediate-wet state (contact angle (CA) = 96°) while that of fracture surfaces became strongly oil-wet (CA = 139°). Consequently, the fracture oil layer grew in size on both fracture surfaces and imbibed into the proppant pack through piston-like displacement and pore body filling until oil bridges were formed during oil injection. However, subsequent waterflooding induced thinning and rupturing of those bridges due to the accompanying reduction in the threshold capillary pressure of the proppant at higher aging times. The in situ chemical treatment of the proppant by a cationic surfactant (dodecyl tri-methyl ammonium bromide) could reverse its wettability toward weakly water-wet state (CA = 78°) after oil solubilization from the sand grains followed by substitutive surfactant adsorption. Surfactant injection also impacted the wettability of the fracture surface due to oil solubilization, reducing its mean contact angle down to an intermediate range (CA = 99°). As a result, the following oil production cycle yielded a smaller fracture oil layer. The surfactant effect on proppant wettability lasted for 2 weeks while its effect on fracture wettability lasted for more than 6 weeks. Similar flow cycles were performed with an anionic nanoparticle (graphene quantum dot) with hydrogen bonding ability. The nanoparticle solution yielded a quick reduction of the proppant and fracture surface contact angles to nearly 77° and 115°, respectively. Proppant wettability alteration occurred because the nanoparticles self-assembled at the three-point contact region between adsorbed oil and quartz surfaces, leading to oil solubilization in intermediate-wet regions while oil-wet regions remained unchanged. Therefore, re-introducing oil into the fracture instantaneously re-instated the initial wettability state of proppant grains (CA = 88°), deeming the nanoparticle solution ineffective. This study revealed that oil production through hydraulic fractures can be enhanced by monitoring the wettability of the proppant pack. If the production has a high water cut, it is beneficial to use chemical agents that reduce the proppant contact angles to a weakly water-wet state in order to preserve the hydraulic conductivity of the oil layer.

Initiation and termination of liquid flow controlled drying collapse of interconnected parenchyma cells in palm wood

The underlying mechanisms of drying collapse in liquid-filled oil palm wood (OPW) have been explored. By systematically varying the liquid surface tension inside the OPW, different degrees of drying collapse commonly observed throughout the whole trunk were shown to be initiated at identical threshold capillary pressure. Microstructural examination confirmed that despite having different sizes and wall thicknesses, the thin-wall parenchyma cells possess a roughly constant wall thickness-to-radius ratio to resist buckling. The equivalent behavior of drying collapse and mechanical collapse under compression of saturated OPW was demonstrated to prove that the drying collapse is controlled by the flow of liquid through the wood. Less collapse corresponds to the lower permeability of the liquid through the wood cells. Variation in the post-collapse behavior is a result of the initiation and termination of the liquid flow inside the interconnected parenchyma cell cavities through small pit openings of plasmodesmata of various distributions. This new understanding provides insight into the drying collapse mechanism of the liquid-filled partially closed-cell foam of a similar structure.

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.

Microscopic production characteristics of tight oil in the nanopores of different CO2-affected areas from molecular dynamics simulations

Understanding the mechanisms of CO2 extraction or flooding are vital for enhancing oil recovery (EOR) in tight reservoirs. In this study, the CO2 EOR mechanism in the displacement-affected area (DPAA) and diffusion-affected area (DFAA) of quartz nanopores were thoroughly investigated using molecular dynamics simulation techniques. First, the following two contents were mainly simulated, namely CO2 flooding oil in the single/double nanopores of DPAA and CO2 extraction oil in dead-end nanopores of the DFAA with and without the water film. Then, tight oil potential energy, threshold capillary pressure, CO2 solubility, and oil swelling in nanopores were calculated to clarify the effects of CO2 on oil transport. Moreover, different CO2 injection/flowback rates and different water film thicknesses on dead-end nanopores on oil recovery were discussed. In the DPAA, the CO2 solubility and the oil swelling factor gradually decreased with distance from the CO2-oil interface (Y = 0 nm), where the higher the injection rate, the more easily the CO2 dissolved in the oil. However, the injection rate of CO2 was inversely proportional to oil recovery. In addition, it took longer for the displacement efficiency in the 6 nm pore of double pores to reach the same displacement efficiency as in the single 6 nm pore. In the DFAA, the effect of flowback rate on the displacement efficiency of oil was relatively low. However, the thickness of the water film was a key factor that affected the oil displacement efficiency in the DFAA.

Theoretical comparison of two setups for capillary pressure measurement by centrifuge

There are several approaches for the calculation of capillary pressure curves in porous media including the centrifuge method. In this work, a new installation of centrifuge test is introduced and compared with the traditional setup. In the first setup, which is a standard approach in labs, the core face closest to the rotational axis is open to the non-wetting phase, while the farthest face is open to the wetting phase where strictly co-current flow is generated in rotations; labeled Two-Ends-Open (TEO). In the second setup, which is proposed as a new approach, only the outer radius surface is open and is exposed to the light non-wetting phase; labeled One-End-Open (OEO). This setup strictly induces counter-current flow. The two systems and their corresponding boundary conditions are formulated mathematically and solved by a fully implicit numerical solver. The TEO setup is validated by comparison with commercial software. Experimental data from the literature are used to parameterize the models. It is mathematically, and with examples, demonstrated that the same equilibrium is obtained in both systems with the same rotational speed, and changing the installation does not influence the measured capillary pressure. This equilibrium state is only dependent on the rotational speed, rock capillary pressure properties, and fluid densities, not the installation geometry, relative permeabilities, or fluid viscosities. However, the dynamic transition trend and saturation profiles were found to be dependent on the applied installation. It was observed that the OEO setup takes almost identical equilibration time as the TEO setup for mixed-wet states, although it needed much longer time in water-wet states. The presence of threshold capillary pressure significantly increased the time scale of the OEO setup. Also, it was found that in contradiction to the TEO setup, the dynamic saturation profile in OEO was rarely influenced by viscosity ratio. To conclude, the performed history matching analysis demonstrated that the OEO setup can be applied for the calculation of counter-current relative permeability from the production data with reasonable accuracy.

Subsurface multiphase reactive flow in geologic CO2 storage: Key impact factors and characterization approaches

Subsurface multiphase reactive flow in geologic CO2 storage: Key impact factors and characterization approaches

Modified Johnson–Bossler–Naumann method to incorporate capillary pressure boundary conditions in drainage relative permeability estimation

A proposed modification of the Johnson–Bossler–Naumann (JBN) method incorporates capillary pressure at the inlet and outlet of a rock sample. The experimental runs are performed on Berea and Obernkriechner sandstone rock samples. Fluid is injected into Berea rock at capillary to viscous ratios 0.05, 0.1, 0.5, and 1 and into Obernkriechner rock at capillary to viscous ratios 0.05 and 0.25. Rock samples are initially saturated with 20 g/l NaCl water. The experimental observations are analyzed using classical JBN and our modified JBN. The latter's relative permeability curves are found to closely match those derived by applying history matching to a numerical model. This indicates that modified JBN can be used to provide an initial guess for history matching. We also show that accurate estimates of threshold capillary pressure are crucial to obtaining accurate oil relative permeability estimates. In contrast to those derived from the JBN method, modified JBN relative permeabilities are independent of capillary to viscous ratio or injection rate. • The proposed model incorporates capillary pressure at the inlet and outlet boundary. • Experiments are performed to validate the model. • Derived relative permeability curves are less sensitive to capillary number compared to classical methods.

Numerical investigation of inertial, viscous, and capillary effects on the drainage process in porous media

The drainage process in porous media, where a non-wetting fluid displaces a wetting fluid, has been studied by considering viscous and capillary effects. However, inertial effects on the drainage process had not been widely studied until recently. Here, we numerically simulate the drainage process in a randomly generated two-dimensional porous medium using the color-gradient lattice Boltzmann method, for capillary numbers Ca=10−3 and 10−5 and Reynolds numbers Re from 0.1 to 50 to demonstrate inertial effects for both larger and smaller capillary numbers. The effects on saturation, interfacial lengths, and capillary pressure during the displacement process and the invasion patterns are analyzed. The results indicate an increase in saturation of the invading non-wetting fluid as the inertial effects become larger. Larger inertia increases the fluid interfacial length for Ca=10−3, whereas it does not affect the interfacial length for Ca=10−5. In regard to capillary pressure, Ca=10−3 produces a larger capillary pressure for larger inertial effects. For Ca=10−5, the capillary pressure fluctuates around the mean threshold capillary pressure of the porous medium, and inertial effects are minor during most of the invasion. In addition, an analysis of the invasion sequence reveals that a more compact invasion is produced by larger inertial effects, and for Ca=10−5, going against the capillary fingering dynamics, a continuous invasion from the inlet region is observed. This study adds the effects of inertia to the well-known viscous–capillary interplay and extends our understanding of the invasion process in porous media.

Using Direct Numerical Simulation of Pore-Level Events to Improve Pore-Network Models for Prediction of Residual Trapping of CO2

Direct numerical simulation and pore-network modeling are common approaches to study the physics of two-phase flow through natural rocks. For assessment of the long-term performance of geological sequestration of CO2, it is important to model the full drainage-imbibition cycle to provide an accurate estimate of the trapped CO2. While direct numerical simulation using pore geometry from micro-CT rock images accurately models two-phase flow physics, it is computationally prohibitive for large rock volumes. On the other hand, pore-network modeling on networks extracted from micro-CT rock images is computationally efficient but utilizes simplified physics in idealized geometric pore elements. This study uses the lattice-Boltzmann method for direct numerical simulation of CO2-brine flow in idealized pore elements to develop a new set of pore-level flow models for the pore-body filling and snap-off events in pore-network modeling of imbibition. Lattice-Boltzmann simulations are conducted on typical idealized pore-network configurations, and the interface evolution and local capillary pressure are evaluated to develop modified equations of local threshold capillary pressure of pore elements as a function of shape factor and other geometrical parameters. The modified equations are then incorporated into a quasi-static pore-network flow solver. The modified model is applied on extracted pore-network of sandstone samples, and saturation of residual trapped CO2 is computed for a drainage-imbibition cycle. The modified model yields different statistics of pore-level events compared with the original model; in particular, the occurrence of snap-off in pore-throats is reduced resulting in a more frontal displacement pattern along the main injection direction. Compared to the original model, the modified model is in closer agreement with the residual trapped CO2 obtained from core flow experiments and direct numerical simulation.

Effect of elastic instability on mobilization of capillary entrapments

The flow of viscoelastic polymer solutions and their use as displacing agents in porous media are important for industrial applications, such as enhanced oil recovery and soil remediation. The complexity of flow and high elasticity of conventionally used viscoelastic polymer solutions can lead to purely elastic instability in porous media. In this study, we investigate the impact of this instability on displacing capillary entrapments at low Reynolds numbers using a microfluidic approach. Our unique design consists of a single-capillary entrapment connected to two symmetric serpentine channels. This design excludes the effect of viscous forces and enables a direct focus on displacement processes driven solely by elastic forces. After the onset of purely elastic instability, an unstable base flow is observed in the serpentine channels. We discuss that the pressure fluctuations caused by this unstable flow create an instantaneous non-equilibrium state between the two ends of the capillary entrapment. This provides the driving pressure to overcome the capillary threshold pressure and eventually displace the entrapped oil. In our geometry, we observe that the displacement coincides with the emergence of a fully developed elastic turbulent state.

The Effect of Authigenic Clays on Fault Zone Permeability

AbstractClays are understood to form the majority of fluid‐flow barriers in faulted reservoirs and numerous fault gouge and fault seal studies have quantified the volumes of smeared and abraded clays create fluid‐flow barriers along fault surfaces. However, clay‐related permeability adjacent to the fault surface, including in the fault damage zone, has largely been neglected. Previous studies have shown the morphology and distribution of unfaulted authigenic clays, and not just clay volume, exert a significant control on the magnitude of permeability. However, fault‐related studies have neither characterized deformed authigenic clays nor addressed their influence on fluid‐flow. In this study laboratory permeabilities of faulted, authigenic clay bearing sandstones sampled from the Otway basin (Australia) and the Orcadian basin (UK) present trends which; (a) do not correspond to expected patterns of fluid‐flow in faulted clay‐bearing sandstones and, (b) cannot be explained using published models of permeability related to changing clay volume. Microscopic analysis shows that faulting has disaggregated authigenic clays and, similarly to framework grain deformation, comminuted and sheared clay grains. However, instead of impeding fluid‐flow, analysis of pore networks (using mercury injection porosimetry) showed that faulting of authigenic clays has increased pore connectivity, contributing to increased magnitude of permeability and development of permeability anisotropy. Contrary to published results of faulting and fluid‐flow in impure sandstones, our results show that fault related processes involving the formation of clays in the fault zone can increase permeability and reduce the capillary threshold pressures of fault rocks relative to the unfaulted host rock.

Microscale investigation of DNAPL displacement by engineered graphene quantum dots in heterogeneous porous media

This x-ray microtomography study investigates the dynamic pore-scale displacement of a dense non-aqueous phase liquid (DNAPL) such as heavy crude oil in a heterogeneous aquifer rock using carbonaceous nanoparticles. The nanoparticles were synthesized from Wyoming coal and consisted of a mixture of graphene quantum dots (GQD) and engineered graphene quantum dots (E-GQD) in equal proportions. Synergistic interactions between GQD and E-GQD at the oil/water interface reduced the DNAPL/brine interfacial tension (IFT) from 13.4 mN/m to 5.4 mN/m. In addition, the nanofluid mixture altered the wettability of the minerals found in the rock (quartz, carbonate, and feldspar) from oil-wet to water-wet with average contact angles of 66°, 51°, and 60°, respectively. The wettability alteration was more pronounced in carbonates due to the tendency of GQD to adsorb on these surfaces. Analyses of the saturation profiles and pore-scale fluid occupancy maps revealed that the wettability alteration was not instantaneous and required a short soaking time for the fluid-rock interactions to take place. IFT reduction alone was not enough to displace the DNAPL at the early stages of nanofluid flooding because of the high density and viscosity of the oil. As a result, the nanofluid did not outperform brine after 1 pore volume (PV) of injection. On the other hand, the nanofluid was able to invade small pores that were not accessible to brine after 3 PV of injection due to both IFT and contact angle reduction, which lowered the threshold capillary pressure of these pores. Subsequently, more medium and large pores were invaded by the nanofluid as the injection continued, leading to an 11% increase in DNAPL recovery after 20 PV of nanofluid injection, as compared to waterflooding. This incremental recovery is significant considering that the experiments were performed with a heavy oil at ambient temperature, which is more representative of aquifer conditions. Thus, the GQD-based nanofluid has the potential to achieve much larger recoveries in deeper heavy oil reservoirs provided enough soaking time is allowed. The insights provided by this study could be used to validate pore-scale network models or guide in the design and selection of more effective nanomaterials for aquifer remediation or enhanced oil recovery applications.