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Abstract Due to the unique properties of nanoparticles (NPs), their application has been proposed as an innovative and promising enhanced oil recovery (EOR) technique. They enhance oil recovery by improving EOR mechanisms including decreasing interfacial tension (IFT), wettability alteration to water-wet, and preventing asphaltene precipitation. In this study, Fe3O4@Gelatin NPs were synthesized by a convenient and single-step method and then investigated for EOR purposes for the first time. These NPS were characterized by Transmission Electron Microscopy (TEM), X-ray diffraction (XRD), and Fourier-transform infrared spectroscopy (FTIR). Afterward, various experiments including contact angle, interfacial tension (IFT), and micromodel flooding were performed to evaluate the capability of Fe3O4@Gelatin NPs for EOR application. Based on the results of IFT measurements, the synthesized NPs caused the highest reduction in IFT of crude oil-seawater compared to Fe3O4 NPs and gelatin. This significant reduction is due to the synergistic effects of Fe3O4 NPs and gelatin in the form of a nanocomposite. According to the results from contact angle measurements, the Fe3O4@Gelatin NPs could significantly change the glass surface wettability from oil-wet to water-wet, which showed a better performance than Fe3O4 NPs. The surface modification of Fe3O4 NPs with gelatin causes to enhance the capability of these NPs for wettability alteration because the gelatin has surface active property. In the micromodel flooding tests, the seawater containing 0.06 wt. % Fe3O4@Gelatin NPs had the highest oil recovery factor (RF = 42.9%) compared to the seawater containing 0.06 wt. % Fe3O4 NPs (RF = 33.92%) and only seawater (RF = 26.57%), due to more IFT reduction and altering the surface wettability from oil-wet to strongly water-wet. Therefore, according to the results of this research, the synthesized NPs can be a good option for EOR.

Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO2 co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO2, Al2O3 nanoparticles, anionic surfactant SDS, and CO2 in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO2 foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO2 from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.

Many oil reservoirs face production decline, so using enhanced oil recovery methods and well stimulation techniques to increase well productivity has been beneficial and essential. Acid injection into the rock matrix is one of the best stimulation methods to improve oil production. The type of acid used in acid injection operations varies based on reservoir conditions, such as temperature, lithology, and acid‐rock contact time. Reservoir heterogeneity, such as the density and orientation of fractures, affects the performance of acidizing operations. Fracture orientation affects the hydraulic conductivity of post‐acid formation in the near‐wellbore area. In this study, the effect of fracture orientation on acid flow in porous media was visually observed using a transparent cell (micromodel). Image processing techniques were employed to study acid distribution in the carbonate‐fractured rock sample. The results showed that the effectiveness of acid treatment is higher in intersecting fractures compared to parallel fractures, and in parallel fractures compared to fractures perpendicular to the flow direction. At the end of the acid injection, the cumulative dimensionless index (DI), defined as the ratio of the aperture surface area to the surface area in contact with the acid, was 0.57, 0.38, and −0.11 for the crossed, parallel, and vertical fractures, respectively. The aperture surface area refers to the total area of the openings within the fracture network, while the surface area in contact with the acid denotes the portion of the fracture surface directly exposed to the acid during the acidizing process. This introduced index quantitatively measures acidizing effectiveness in widening fracture networks in carbonate reservoirs providing insight into alterations in fracture size and permeability due to acid treatment. After three stages of acid injection, the DI for the fracture aperture in the parallel section of intersecting fractures is 33.3% higher than that for the fracture aperture in the parallel fracture. Considering the additional fracture aperture in the vertical sections of the intersecting fractures, compared to parallel fractures, the superior effectiveness of intersecting fractures becomes more evident. Nevertheless, vertical fractures demonstrated minimal and sometimes negative impact. Fracture orientation impacts acidizing operations, guiding strategies for better production, recovery rates, and reservoir characterization in the oil industry. [ABSTRACT FROM AUTHOR]

Abstract Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors.

Our target USH reservoir in the D oilfield is characterized by "inverse rhythm" deposition with the noticeable features of "high porosity and low permeability". The reservoir has been developed with waterflooding using horizontal wells. Due to the strong heterogeneity of the reservoir, water channeling is severe, and the water cut has reached 79%. Considering the high temperature and high salinity reservoir conditions, polymer microspheres (PMs) were selected to realize conformance control. In this study, characterization of the polymer microsphere suspension was achieved via morphology, size distribution, and viscosity measurement. Furthermore, a multi-scale visualization study of the reservoir development process, including waterflooding, polymer microsphere flooding, and subsequent waterflooding, was conducted using macro-scale coreflooding and calcite-etched micromodels. It was revealed that the polymer microspheres could swell in the high salinity brine (170,000 ppm) by 2.7 times if aged for 7 days, accompanied by a viscosity increase. This feature is beneficial for the injection at the wellbore while swelled to work as a profile control agent in the deep formation. The macro-scale coreflood with a 30 cm × 30 cm × 4.5 cm layer model with 108 electrodes installed enabled the oil distribution visualization from different perpendicular cross sections. In this way, the in situ conformance control ability of the polymer microsphere was revealed both qualitatively and quantitatively. Furthermore, building on the calcite-etched visible micro-model, the pore-scale variation of the residual oil when subjected to waterflooding, polymer microsphere waterflooding, and subsequent waterflooding was collected, which revealed the oil displacement efficiency increase by polymer microspheres directly. The pilot test in the field also proves the feasibility of conformance control by the polymer microspheres, i.e., more than 40,000 bbls of oil increase was observed in the produces, accompanied by an obvious water reduction. [ABSTRACT FROM AUTHOR]

The induced polarization (IP) method holds a strong potential to better characterize the critical zone of our planet especially in areas characterized by multi‐phase flow. Power‐law relationships between the bulk, surface, and quadrature conductivities versus the pore water saturation are potentially useable to map the subsurface water content distribution. However, the saturation exponents n and p in these power‐law relationships have been observed to vary with the texture of geomaterials and the wettabilities of pore fluids. Traditional experimental setups in the laboratory do not allow to independently visualize the pore fluid distribution. Therefore, the physical interpretations of the two saturation exponents have remained unclear. We developed a novel milli‐fluidic micromodel using clay‐coated glass beads that exhibit excellent visibility and high IP response. Through laboratory experiments, we simultaneously determined the micromodel complex conductivity and acquired the corresponding pore‐scale fluid distributions generated by drainage and imbibition through such class of porous materials. Finite‐element simulations of complex conductivity based on the upscaling of the complex surface conductance of grains were conducted to determine the saturation exponents under ideal pore fluid distributions. Results indicate that saturation exponents n and p vary depending on the ganglia size of the insulating fluids. The saturation exponents n and p exhibit power‐law relationships with the change rate of pore water connectivity with saturation, which is calculated through the computation of the derivative of Euler characteristics. These findings provide a new physical explanation to the relationships between the saturation exponents and the microscopic fluid distributions within the geomaterials. Plain Language Summary: Water saturation of porous bodies can be related to the complex conductivity through power‐law relationships. The existence of these power‐law relationships has been clearly documented in the literature. They are critical in the realm of hydrogeophysics to better characterize the critical zone of the solid Earth. However, the values of the saturation exponents in these power‐laws have been observed to vary with different material textures and no underlying mechanisms have been able to explain these variations to date. This lack of physical understanding could limit the applicability of the induced polarization method to characterize the critical zone especially when immiscible fluid phases are present. To tackle this, we developed a milli‐fluidic pore model that allows investigating the saturation exponents while monitoring the pore‐scale fluid distributions. Together with numerical simulations for ideal fluid distribution cases, we found a relationship between the saturation exponents and a microscopic pore parameter called "change rate of the pore water connectivity with saturation." These findings suggest that when estimating subsurface water saturation from electrical parameters, taking the pore fluid distribution into account can significantly improve the estimation accuracy, therefore enhancing the efficiency of geo‐electrical applications for a better characterization of hydrocarbon contaminated aquifers and oil reservoirs. Key Points: A micromodel setup allows for simultaneous pore fluid visualization and complex electrical conductivity measurementThe two saturation exponents for the in‐phase and quadrature conductivities are correlated with the ganglia size of the insulating phaseA power‐law‐type relationship between the saturation exponents and the change rate of water connectivity with saturation is demonstrated [ABSTRACT FROM AUTHOR]

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors. [ABSTRACT FROM AUTHOR]

The use of diethylenetriaminepentaacetic acid (DTPA) chelating agent has shown promising results for enhanced oil recovery (EOR) in prior research. Several mechanisms, mainly resulting from rock-fluid interaction, have been proposed for chelating agent flooding; however, little attention has been paid to fluid-fluid interaction thus far. The assessment of these mechanisms has primarily relied on macroscopic techniques such as core flooding. This paper aims to investigate the injection of DTPA brine and its dominant mechanisms at the pore scale using a clay-coated micromodel. The micromodel tests were performed under oil-wet and water-wet states. For a more precise examination of fluid/fluid interactions, the dynamic interfacial tension (IFT) and Zeta potential were measured. It was observed that the injection of DTPA brine in water-wet state changed the saturation distribution and increased oil recovery. Based on visual inspections, this change in saturation distribution could potentially be linked to the formation of micro-dispersions and viscoelastic interfacial phenomena. Micro-dispersions facilitate flow to unswept areas, and viscoelastic interface formation reshapes the interface between oil and brine, causing disconnected oil droplets to coalesce and thus increase recovery. Under the oil-wet state, the micro-dispersion formation and wettability alteration can be the dominant mechanisms, and the amount of recovered oil was higher than that observed in the water-wet state. Furthermore, Zeta potential measurements at the interface between brine and oil showed a more negative value for DTPA brine, which is effective in wettability alteration and micro-dispersions stability. The results indicate that IFT reduction was not significant enough to be considered the dominant mechanism, although it assists in DTPA brine penetration into the crude oil and subsequent micro-dispersion formation.

Abstract This paper introduces a hybrid enhanced oil recovery (HEOR) method that combines a low-salinity water flooding (LSWF) and nanoparticles (NPs) stabilized with a green surfactant. We experimentally investigated the use of combinations of silica (SiO2) and gamma alumina (γ-Al2O3) nanohybrids stabilized with Gum Arabic (GA) at different water salinities. Nanofluids (NFs) were prepared by dispersing γ-Al2O3 and SiO2 NPs (0.1 wt%) in deionized water (DW), synthetic seawater (SSW), 2, 5, and 10 times diluted samples of synthetic seawater (in short 2-DSSW, 5-DSSW and 10-DSSW, respectively). The challenge is that NPs become unstable in the presence of cations in saline water. Moreover, an attempt was made to introduce NFs with high stability for a long period of time as the optimal NFs. The effects of temperature on the behaviour of optimal NFs in the presence of different base fluids, distinct mass ratios of γ-Al2O3/SiO2 and various concentrations of surfactant were analysed via interfacial tension (IFT) and viscosity measurements. The results of the viscosity measurement showed that with increasing temperature, the NPs dispersed in DW had lower viscosity than NPs dispersed in various salinities. However, the IFT measurement for NPs dispersed in different base-fluids revealed that with increasing temperature and presence of cations in saline water, IFT values decreases. Although, the minimum IFT for hybrid nanofluid (HNF) γ-Al2O3/SiO2 modified with GA and dispersed in 10-DSSW was reported 0.99 mN/m. Finally, according to the micromodel flooding results, in oil-wet conditions, the highest oil recovery for combination γ-Al2O3/SiO2 modified with GA and dispersed in 2-DSSW was reported 60.34%. It was concluded that NFs modified with GA could enhanced applicability of LSWF via delay in breakthrough time and improving sweep efficiency.

Abstract This project investigated the impact of low-temperature, in-situ synthesis of cerium oxide (CeO2) nanoparticles on various aspects of oil recovery mechanisms, including changes in oil viscosity, alterations in reservoir rock wettability, and the resulting oil recovery factor. The nanoparticles were synthesized using a microemulsion procedure and subjected to various characterization analyses. Subsequently, these synthesized nanoparticles were prepared and injected into a glass micromodel, both in-situ and ex-situ, to evaluate their effectiveness. The study also examined the movement of the injected fluid within the porous media. The results revealed that the synthesized CeO2 nanoparticles exhibited a remarkable capability at low temperatures to reduce crude oil viscosity by 28% and to lighten the oil. Furthermore, the addition of CeO2 nanoparticles to the base fluid (water) led to a shift in the wettability of the porous medium, resulting in a significant reduction in the oil drop angle from 140° to 20°. Even a minimal presence of CeO2 nanoparticles (0.1 wt%) in water increased the oil production factor from 29 to 42%. This enhancement became even more pronounced at a concentration of 0.5 wt%, where the oil production factor reached 56%. Finally, it was found that the in-situ injection, involving the direct synthesis of CeO2 nanoparticles within the reservoir using precursor salts solution and reservoir energy, led to an 11% enhancement in oil production efficiency compared to the ex-situ injection scenario, where the nanofluid is prepared outside the reservoir and then injected into it.

Through the development of a mathematical model for micro-scale multi-phase flow of supercritical CO2 and a simplified geological reservoir micro-model, numerical simulations were executed using the open-source CFD software Open FOAM. The study systematically analyzed various engineering and geological parameters' influence on the micro-scale flow patterns of supercritical CO2 under reservoir temperature and pressure conditions. These insights provide guidance for designing process parameters in fracturing and storing supercritical CO2. [ABSTRACT FROM AUTHOR]

Increasing world request for energy has made oil extraction from reservoirs more desirable. Many novel EOR methods have been proposed and utilized for this purpose. Using nanocomposites in chemical flooding is one of these novel methods. In this study, we investigated the impact of six injection solutions on the recovery of light and heavy oil with the presence of two different brines as formation water using a homogenous glass micromodel. All of the injection solutions were based on a 40,000 ppm NaCl synthetic seawater (SSW), one of which was additive free and the others were prepared by dispersing nanocomposite silica-based polyacrylamide (NCSP), nanocomposite alumina-based polyacrylamide (NCAP), the combination of both nanocomposites silica and alumina based on polyacrylamide (NCSAP), surfactant (CTAB) and polyacrylamide (PAM) with a concentration of 1000 ppm as additives. The Stability of nanocomposites was tested against the salinity of the brine and temperature using salinity and DSC tests which were successful. Alongside stability tests, IFT, contact angle and oil recovery measurements were made. Visual results revealed that in addition to the effect of silica and alumina nanocomposite in reducing interfacial tension and wettability alteration, control of mobility ratio caused a major improvement in sweeping efficiency and oil recovery. According to the sweeping behavior of injected fluids, it was found that the main effect of surfactant was wettability alteration, for polyacrylamide was mobility control and for nanocomposites was the reduction of interfacial tension between oil and injected fluid, which was completely analyzed and checked out. Also, NCSAP with 95.83% and 70.33% and CTAB with 84.35% and 91% have the highest light oil recoveries at 250,000 ppm and 180,000 ppm salinity, respectively which is related to the superposition effect of interactions between nanocomposites, solution and oil. Based on our results it can be concluded that the most effective mechanism in oil recovery was IFT reduction which was done by CTAB reduction also by using a polymer-based nanocomposite such as NCSAP and adding the mobility control factor, the oil recovery can be further enhanced. In the case of heavy oil recovery, it can be concluded that the mobility control played a much more effective role when the PAM performed almost similarly to the CTAB and other nanocomposites with a recovery factor of around 17%. In this study, we tried to investigate the effect of different injection solutions and their related mechanisms on oil recovery. [ABSTRACT FROM AUTHOR]

This project investigated the impact of low-temperature, in-situ synthesis of cerium oxide (CeO2) nanoparticles on various aspects of oil recovery mechanisms, including changes in oil viscosity, alterations in reservoir rock wettability, and the resulting oil recovery factor. The nanoparticles were synthesized using a microemulsion procedure and subjected to various characterization analyses. Subsequently, these synthesized nanoparticles were prepared and injected into a glass micromodel, both in-situ and ex-situ, to evaluate their effectiveness. The study also examined the movement of the injected fluid within the porous media. The results revealed that the synthesized CeO2 nanoparticles exhibited a remarkable capability at low temperatures to reduce crude oil viscosity by 28% and to lighten the oil. Furthermore, the addition of CeO2 nanoparticles to the base fluid (water) led to a shift in the wettability of the porous medium, resulting in a significant reduction in the oil drop angle from 140° to 20°. Even a minimal presence of CeO2 nanoparticles (0.1 wt%) in water increased the oil production factor from 29 to 42%. This enhancement became even more pronounced at a concentration of 0.5 wt%, where the oil production factor reached 56%. Finally, it was found that the in-situ injection, involving the direct synthesis of CeO2 nanoparticles within the reservoir using precursor salts solution and reservoir energy, led to an 11% enhancement in oil production efficiency compared to the ex-situ injection scenario, where the nanofluid is prepared outside the reservoir and then injected into it. [ABSTRACT FROM AUTHOR]

Abstract This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While “smart water” injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0–2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3–5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions.

The study demonstrates the significant enhancement in oil production from a Romanian oil field using alkali–polymer (AP) flooding for reactive viscous oil. We conducted comprehensive interfacial tension (IFT) measurements across various alkali and AP concentrations, along with phase behavior assessments. Micromodel flooding experiments were used to examine pore-scale effects and select appropriate chemical concentrations. We tested displacement efficiency at the core level and experimented with different sequences and concentrations of alkali and polymers to minimize costs while maximizing the additional recovery of reactive viscous oil. The IFT analysis revealed that saponification at the oil–alkali interface significantly lowers IFT, but IFT gradually increases as soap diffuses away from the interface. Micromodels indicated that polymer or alkali injection alone achieve only minimal incremental recovery beyond waterflooding. However, AP flooding significantly enhanced incremental oil recovery by efficiently moving the mobilized oil with the viscous fluid and increasing exposure of more oil to the alkali solution. Coreflood experiments corroborated these findings. We also explored how divalent cations influence polymer concentration selection, finding that softening the injection brine significantly increased the viscosity of the AP slug. [ABSTRACT FROM AUTHOR]

This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While "smart water" injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0–2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3–5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions. [ABSTRACT FROM AUTHOR]

Abstract Swelling and migration of present clays make damage to the oil reservoirs due to low salinity waterflooding (LSWF) can induce serious problems in the case of oil recovery improvement and researchers are trying to solve this problem. The purpose of this work is to investigate the mechanism of two phenomena of swelling and migration clays in the porous media of a reservoir rock by injecting a different composition of LSWF using a glass micromodel and providing the appropriate composition and pattern of injection with the removal of damage. Proper water flooding design, application of efficient swelling inhibitors, and migration control are among the most important methods to overcome the problem of formation damage due to swelling and migration of clays. A series of static (bulk or bottle test) and dynamic tests were carried out using a micromodel with a coating of kaolinite and montmorillonite clays in the vicinity and injection of different low salt water compositions. The type and amount of these clays were selected based on the results of XRD and SEM mineralogical tests on real reservoir rock, FW and diluted FW, SW and diluted SW, solution of 1% zirconium oxychloride in 20 times diluted seawater (SI), and composition of nanofluid MgO, SiO2, and Al2O3 in 20 times diluted. In the studies conducted by the micromodel, only the images taken were used in the analysis of the mechanisms, but here, the input and output pressures of the micromodel were recorded with high-precision pressure transmitters, and by using the differential pressure, the permeability was calculated and the formation damage index was introduced. The overlap of the interpretation of the captured images and the changes of the numerical parameter of the damage index in all stages of injection of smart water composition was considered to evaluate the simultaneous and separate mechanisms of swelling and migration of clays. The results of the experiments in this research show that clay swelling has destructive effects on permeability, and migration due to the transfer of clays from the porous medium can have promising effects on reducing the damage index in some conditions. And it is necessary to use the swelling control compound during the flooding process, but the migration inhibitor compound is not always suitable. Gradual reduction of salinity is also introduced as a pattern to prevent swelling damage or clay migration. In general, in this study, the best design and fluid engineering for smart water injection with the least damage in the micromodel scale was presented.

Swelling and migration of present clays make damage to the oil reservoirs due to low salinity waterflooding (LSWF) can induce serious problems in the case of oil recovery improvement and researchers are trying to solve this problem. The purpose of this work is to investigate the mechanism of two phenomena of swelling and migration clays in the porous media of a reservoir rock by injecting a different composition of LSWF using a glass micromodel and providing the appropriate composition and pattern of injection with the removal of damage. Proper water flooding design, application of efficient swelling inhibitors, and migration control are among the most important methods to overcome the problem of formation damage due to swelling and migration of clays. A series of static (bulk or bottle test) and dynamic tests were carried out using a micromodel with a coating of kaolinite and montmorillonite clays in the vicinity and injection of different low salt water compositions. The type and amount of these clays were selected based on the results of XRD and SEM mineralogical tests on real reservoir rock, FW and diluted FW, SW and diluted SW, solution of 1% zirconium oxychloride in 20 times diluted seawater (SI), and composition of nanofluid MgO, SiO2, and Al2O3 in 20 times diluted. In the studies conducted by the micromodel, only the images taken were used in the analysis of the mechanisms, but here, the input and output pressures of the micromodel were recorded with high-precision pressure transmitters, and by using the differential pressure, the permeability was calculated and the formation damage index was introduced. The overlap of the interpretation of the captured images and the changes of the numerical parameter of the damage index in all stages of injection of smart water composition was considered to evaluate the simultaneous and separate mechanisms of swelling and migration of clays. The results of the experiments in this research show that clay swelling has destructive effects on permeability, and migration due to the transfer of clays from the porous medium can have promising effects on reducing the damage index in some conditions. And it is necessary to use the swelling control compound during the flooding process, but the migration inhibitor compound is not always suitable. Gradual reduction of salinity is also introduced as a pattern to prevent swelling damage or clay migration. In general, in this study, the best design and fluid engineering for smart water injection with the least damage in the micromodel scale was presented. [ABSTRACT FROM AUTHOR]

With the advancement in nanotechnology and the importance of developing enhanced oil recovery methods to extract more hydrocarbons and overcome the challenges of the chemical method, more attention has been given to investigating the effects of various cost-effective and environmentally friendly nanoparticles. Computational fluid dynamic (CFD) has served as an accurate tool to predict crude oil displacement for the enhanced oil recovery process. To the best of our knowledge, few CFD simulations investigating the effect of injecting silica nanofluid into a micromodel have been performed for observing the oil recovery. In this work, simulation of silica nanofluid flooding into a 2D micromodel is studied to replicate a previous experiment of injecting silica nanoparticles with synthetic seawater, in which micromodel flooding was carried out. The micromodel geometry was created using SolidWorks software and ANSYS-Fluent workbench was used for analysing the volume fraction contours. The volume of fluid model and continuum surface force equations were used to model the interaction between wall–fluid to model the wettability of the micromodel wall, and fluid–fluid for oil and nanofluid interaction. Moreover, silica nanofluid properties were estimated by using thermophysical equations. It was observed that injecting silica-based nanofluid into water wet micromodel provided more oil recovery than oil wet micromodel. The comparison between oil recovery from experiment and simulation indicated a relative error of 19% with general good agreements. Furthermore, the low concentration of 0.2% and 1% of nanoparticles provided an oil recovery of 87% and 88% from the oil wet media, respectively. [ABSTRACT FROM AUTHOR]

Geological carbon storage in deep aquifers involves displacement of resident brine by supercritical CO2 (scCO2), which is an unstable drainage process caused by the invasion of less viscous scCO2. The unstable drainage is greatly complicated by aquifer heterogeneity and anisotropy and regarded as one of the key factors accounting for the uncertainty in storage capacity estimates. The impacts of pore-scale characteristics on the unstable drainage remain poorly understood. In this study, scCO2 drainage experiments were conducted at 40 °C and 9 MPa using a homogeneous elliptical micromodel with low or high anisotropy, a homogeneous/isotropic hexagonal micromodel, and a heterogeneous sandstone-analog micromodel. Each initially water-saturated micromodel was invaded by scCO2 at different rates with logCa (the capillary number)ranging from −7.6 to −4.4, and scCO2/water images were obtained. The measured CO2 saturations in these centimeter-scale micromodels vary considerably from 0.08 to 0.93 depending on the pore-scale characteristics and capillary number. It was also observed that scCO2 drainage follows the classic flow-regime transition from capillary fingering through crossover to viscous fingering for either of the low-anisotropy elliptical and heterogeneous micromodels, but with disparate crossover zones. The crossover zones of scCO2 saturation were then unified with the minimum scCO2 saturation occurring at logCa*=-4.0 using the complete capillary number (Ca*)that considers pore characteristics. For the hexagonal and the high-anisotropy elliptical micromodels, a monotonic increase in scCO2 saturation with increasing Ca* (without crossover)was observed. It appears that the complete capillary number is more appropriate than the classic capillary number when characterizing flow regimes and CO2 saturation in different pore networks.

Geological carbon storage in deep aquifers involves displacement of resident brine by supercritical CO2 (scCO2), which is an unstable drainage process caused by the invasion of less viscous scCO2. The unstable drainage is greatly complicated by aquifer heterogeneity and anisotropy and regarded as one of the key factors accounting for the uncertainty in storage capacity estimates. The impacts of pore-scale characteristics on the unstable drainage remain poorly understood. In this study, scCO2 drainage experiments were conducted at 40 °C and 9 MPa using a homogeneous elliptical micromodel with low or high anisotropy, a homogeneous/isotropic hexagonal micromodel, and a heterogeneous sandstone-analog micromodel. Each initially water-saturated micromodel was invaded by scCO2 at different rates with logCa (the capillary number)ranging from −7.6 to −4.4, and scCO2/water images were obtained. The measured CO2 saturations in these centimeter-scale micromodels vary considerably from 0.08 to 0.93 depending on the pore-scale characteristics and capillary number. It was also observed that scCO2 drainage follows the classic flow-regime transition from capillary fingering through crossover to viscous fingering for either of the low-anisotropy elliptical and heterogeneous micromodels, but with disparate crossover zones. The crossover zones of scCO2 saturation were then unified with the minimum scCO2 saturation occurring at logCa*=-4.0 using the complete capillary number (Ca*)that considers pore characteristics. For the hexagonal and the high-anisotropy elliptical micromodels, a monotonic increase in scCO2 saturation with increasing Ca* (without crossover)was observed. It appears that the complete capillary number is more appropriate than the classic capillary number when characterizing flow regimes and CO2 saturation in different pore networks.

Here, Fe2O3 and SiO2 nanoparticles are synthesized and utilized to investigate their effects on foam stability and flowing behavior in porous media. At first, the effect of main operative parameters including surfactant concentration, formation water composition and dosage, and temperature on foam stability are studied at static condition for preparation of an optimal foam solution. Then, the synthesized nanoparticles are dispersed in optimal foam solution for subsequent main experiments. High pressure-high temperature microscopic injection experiments are employed to assess the oil-flow displacement in heterogeneous porous medium pattern by foam injection in the absence and presence of the nanoparticles. The results show that sodium dodecyl sulfonate surfactant concentration of 0.75 wt% provides the optimal dosage independent of other factors. The foam solution becomes unstable with increasing the salinity. Conversely, the presence of more sulfate ions improves the foam stability and foam textural characteristics. In the presence of the synthesized nanoparticles significant enhancement of foam solution stability is observed. Microscopic analysis of the injection experiments in glass micromodel reveals postponement of the displacing fluid breakthrough time, lessening the severity of the finger phenomenon at displacement front, and higher oil recovery for Fe2O3 and SiO2 nanoparticles-assisted foam solutions. However, the enhancement of the foam textural features and flowing behavior are more manifest in the case of SiO2 nanoparticles compared to the Fe2O3 nanoparticles. [ABSTRACT FROM AUTHOR]

Dissolution trapping is one of the most important mechanisms for geological carbon storage (GCS). Recent laboratory and field experiments have shown non-equilibrium dissolution of supercritical CO2 (scCO2) and coupled scCO2 dissolution and water flow, i.e., scCO2 dissolution at local pores/pore throats creating new water-flow paths, which in turn enhance dissolution by increased advection and interfacial area. However, the impacts of pore-scale characteristics on these coupled processes have not been investigated. In this study, imbibition and dissolution experiments were conducted under 40 °C and 9 MPa using a homogeneous/isotropic hexagonal micromodel, two homogeneous elliptical micromodels with low or high anisotropy, and a heterogeneous sandstone-analog micromodel. The four micromodels, initially saturated with deionized (DI)-water, were drained by injecting scCO2 to establish a stable scCO2 saturation. DI water was then injected at different rates with logCa (the capillary number) ranging from −6.56 to −4.34. Results show that bypass of scCO2 by displacing water is the dominant mechanism contributing to the residual CO2 trapping, triggered by heterogeneity in pore characteristics or pore-scale scCO2-water distribution. Bypass can be enhanced by pore heterogeneity or reduced by increasing transverse permeability, resulting in relatively low (

Dissolution trapping is one of the most important mechanisms for geological carbon storage (GCS). Recent laboratory and field experiments have shown non-equilibrium dissolution of supercritical CO2 (scCO2) and coupled scCO2 dissolution and water flow, i.e., scCO2 dissolution at local pores/pore throats creating new water-flow paths, which in turn enhance dissolution by increased advection and interfacial area. However, the impacts of pore-scale characteristics on these coupled processes have not been investigated. In this study, imbibition and dissolution experiments were conducted under 40 °C and 9 MPa using a homogeneous/isotropic hexagonal micromodel, two homogeneous elliptical micromodels with low or high anisotropy, and a heterogeneous sandstone-analog micromodel. The four micromodels, initially saturated with deionized (DI)-water, were drained by injecting scCO2 to establish a stable scCO2 saturation. DI water was then injected at different rates with logCa (the capillary number) ranging from −6.56 to −4.34. Results show that bypass of scCO2 by displacing water is the dominant mechanism contributing to the residual CO2 trapping, triggered by heterogeneity in pore characteristics or pore-scale scCO2-water distribution. Bypass can be enhanced by pore heterogeneity or reduced by increasing transverse permeability, resulting in relatively low (

The rhizosphere is the region of soil directly influenced by plant roots. The microbial community in the rhizosphere includes fungi, protists, and bacteria: all play significant roles in plant health. The beneficial bacterium Sinorhizobium meliloti infects growing root hairs on nitrogen-starved leguminous plants. Infection leads to the formation of a root nodule, where S. meliloti converts atmospheric nitrogen to ammonia, a bioavailable form. In soil, S. meliloti is often found in biofilms and travels slowly along the roots, leaving developing root hairs at the growing root tips uninfected. Soil protists are an important component of the rhizosphere system, able to travel quickly along roots and water films, who prey on soil bacteria and have been known to egest undigested phagosomes. We show that a soil protist, Colpoda sp., can transport S. meliloti down Medicago truncatula roots. Using model soil microcosms, we directly observed fluorescently labeled S. meliloti along M. truncatula roots and tracked the displacement of the fluorescence signal over time. Two weeks after co-inoculation, this signal extended 52 mm farther down plant roots when Colpoda sp. was also present versus treatments that contained bacteria but not protists. Direct counts also showed protists are required for viable bacteria to reach the deeper sections of our microcosms. Facilitating bacterial transport may be an important mechanism whereby soil protists promote plant health. IMPORTANCE Soil protists are an important part of the microbial community in the rhizosphere. Plants grown with protists fare better than plants grown without protists. Mechanisms through which protists support plant health include nutrient cycling, alteration of the bacterial community through selective feeding, and consumption of plant pathogens. Here, we provide data in support of an additional mechanism: protists act as transport vehicles for bacteria in soil. We show that protist-facilitated transport can deliver plant-beneficial bacteria to the growing tips of roots that may otherwise be sparsely inhabited with bacteria originating from a seed-associated inoculum. By co-inoculating Medicago truncatula roots with both S. meliloti, a nitrogen-fixing legume symbiont, and Colpoda sp., a ciliated protist, we show substantial and statistically significant transport with depth and breadth of bacteria-associated fluorescence as well as transport of viable bacteria. Co-inoculation with shelf-stable encysted soil protists may be employed as a sustainable agriculture biotechnology to better distribute beneficial bacteria and enhance the performance of inoculants. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) is a crucial technology in the petroleum industry, influenced by several factors, including flooding fluids and methods. The adjustment of injection strategies and the application of vibration stimulation can significantly impact oil recovery, especially residual oil. In this study, we conducted experiments using a glass micromodel to investigate the effect of pulsing water injection on oil recovery. Our results show that when the pulse frequency matches the natural frequency of the micromodel, resonance occurs during the two-phase flow of pulse driving, which causes an increase in the amplitude of oscillation, enhances the mobility of oil, and improves recovery. The efficiency of the kinetic energy of displacement is also improved. However, when the frequency is 3 Hz, the absence of resonance leads to the opposite effect. In addition, we found that a greater amplitude increases the fluidity of oil. These findings have significant implications for the design of EOR strategies and methods. Our experimental results provide insight into the effect of pulse water injection on oil recovery and offer a potential strategy for the optimization of EOR techniques. [ABSTRACT FROM AUTHOR]

Due to the low porosity and low permeability in unconventional reservoirs, a large amount of crude oil is trapped in micro-to nano-sized pores and throats, which leads to low oil recovery. Nanofluids have great potential to enhance oil recovery (EOR) in low permeability reservoirs. In this work, the regulating ability of a nanofluid at the oil/water/solid three-phase interface was explored. The results indicated that the nanofluid reduced the oil/water interfacial tension by two orders of magnitude, and the expansion modulus of oil/water interface was increased by 77% at equilibrium. In addition, the solid surface roughness was reduced by 50%, and the three-phase contact angle dropped from 135 (oil-wet) to 48 (water-wet). Combining the displacement experiments using a 2.5D reservoir micromodel and a microchannel model, the remaining oil mobilization and migration processes in micro-to nano-scale pores and throats were visualized. It was found that the nanofluid dispersed the remaining oil into small oil droplets and displaced them via multiple mechanisms in porous media. Moreover, the high strength interface film formed by the nanofluid inhibited the coalescence of oil droplets and improved the flowing ability. These results help to understand the EOR mechanisms of nanofluids in low permeability reservoirs from a visual perspective. [ABSTRACT FROM AUTHOR]

Characterizing residual non‐aqueous phase liquids (NAPLs) in porous media is essential for designing contaminated site remediation strategies. The direct current resistivity method is increasingly being used at sites contaminated by NAPLs, which uses the Archie's second law to connect NAPL saturation with the resistivity of porous media. A power‐law relationship connecting the phase morphology measured by Euler characteristic with resistivity has also been observed at the pore‐scale. Because these relationships are limited for porous media with specific wettability, previous research works have demonstrated deviations from Archie's second law in both the laboratory and field experiments. To evaluate the effects of residual NAPL morphology with different wettability on bulk resistivity, we developed two 2D‐micromodels and measured their electrical resistivity and phase morphology during phase displacement under laboratory‐controlled conditions. Furthermore, pore network simulations of a variety of conditions were performed in absence of surface conduction. Results show that NAPL distributed in dead ends of the pore space has limited influence on bulk resistivity since they do not control the current path and voltage distribution. The correlations between resistivity index and Euler characteristic are determined by NAPL ganglia size and pore throat width. A power‐law relationship is found between the Archie's saturation exponent and the average size of the residual NAPL ganglia, indicating that this exponent can be interpreted as the rate of change of the pore water connectivity with saturation. These insights provide a physical framework connecting the morphology and wettability of the NAPL ganglia with the Archie's saturation exponent. Plain Language Summary: Petrophysical relationships can relate the non‐aqueous phase liquids (NAPLs) saturation with subsurface resistivity, which help us to characterize the underground contaminants. However, researchers often encountered deviations from widely adopted petrophysical relationships that link the electrical resistivity with NAPL saturation because they neglect or wrongly predict the effect of NAPL morphology on resistivity. In our study, we systematically explored the mechanism behind the impact of NAPL morphology on electrical resistivity by micromodel experiments and pore network simulation. Key Points: Non‐aqueous phase liquid (NAPL) trapped in dead ends of porous space has little effect on bulk resistivityRelationship between the bulk resistivity and Euler characteristic of partially saturated pore network is determined by NAPL wettabilityA power‐law relationship is found between the Archie's saturation exponent and NAPL ganglia size [ABSTRACT FROM AUTHOR]

The current handling of gas associated with oil production poses an environmental risk. This gas is being flared off due to the technical and economic attractiveness of this option. As flared gases are mainly composed of methane, they have harmful greenhouse effects when released into the atmosphere. This work discusses the effectiveness of using this gas for enhanced oil recovery (EOR) purposes as an alternative to flaring. In this study, a micromodel was designed with properties similar to a sandstone rock with a porosity of 0.4, and computational fluid dynamics (CFD) techniques were applied to design an EOR system. Temperature effects were not considered in the study, and the simulation was run at atmospheric pressure. Five case studies were carried out with different interfacial tensions between the oil and gas (0.005 N/m, 0.017 N/m, and 0.034 N/m) and different injection rates for the gas (1 × 10−3 m/s, 1 × 10−4 m/s, and 1 × 10−6 m/s). The model was compared with a laboratory experiment measuring immiscible gas flooding. Factors affecting oil recoveries, such as the interfacial tension between oil and gas, the viscosity, and the pressure, were studied in detail. The results showed that the surface tension between the oil and gas interphase was a limiting factor for maximum oil recovery. The lower surface tension recovered 33% of the original oil in place. The capillary pressure was higher than the pressure in the micromodel, which lowered the amount of oil that was displaced. The study showed the importance of pressure maintenance to increase oil recovery for immiscible gas floods. It is recommended that a wider set of interfacial tensions between oil and gas be tested to obtain a range at which oil recovery is maximum for EOR with flared gas. [ABSTRACT FROM AUTHOR]

This paper focused on surfactant evaluation targeting the harsh reservoir conditions (high temperature and high salinity fractured reservoir). Six kinds of surfactants were selected and evaluated in terms of interfacial tension (IFT) and contact angle.. S-6 and S-7 presented the best potential ability in IFT reduction among all kinds of surfactant solutions, which were in the 10−2mN/m magnitude. The experiment results showed that the contact angle on oil-wet glass slide at the concentration of 0.2% S-6 was 58°, which is in water-wet region; while other surfactants cannot change the surface wettability.. Finally, the micromodel flooding tests were conducted using S-6, S-7 and S-8 to study both effects of wettability alteration and IFT reduction ability on EOR. The micromodel work was based on an oil-wet etched glass. Compared with S-7, the recovery increase of S-6 was about 12%, indicating that with the similar abilities of IFT reduction for surfactant solutions, the one with stronger wettability alteration ability could lead to a higher oil recovery. As a result, S-6 had better potential in providing higher oil recovery as an imbibition agent. Numerical simulation using UTCHEM suggested that with the increase of injection rate and the decrease of IFT, the imbibition recovery is increased. [ABSTRACT FROM AUTHOR]

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Oil recovery is closely related to the sweep and displacement efficiencies in oil reservoirs. Therefore, several measures have been devised to enhance oil recovery based on these two factors. In heterogeneous heavy oil reservoirs, expansion of the swept volume of medium- and low-permeability layers is a suitable approach for enhancing oil recovery. However, the oil displacement efficiency is also an important factor. With regard to enhancing oil recovery, the selection of displacement agents will depend on whether the sweep efficiency or displacement efficiency is to be adjusted and on how these factors can be controlled to maximise the increase in oil recovery. In this study, the pixel method is used to distinguish between the sweep efficiency and displacement efficiency, and the joint effect of these factors is analysed. A heterogeneous microscopic model is used to conduct oil displacement experiments using polymer solutions with different viscosities and surfactant–polymer systems with similar viscosities and different interfacial tensions. The results indicate that under heterogeneous conditions, increasing the viscosity of the polymer solution leads to a slight expansion in the swept volume and an increase in the oil displacement efficiency in the low-permeability area; however, the overall sweep efficiency remains almost unchanged. There is a critical point for sweep efficiency: under the experimental conditions, when the oil viscosity is 305 mPa s, the critical viscosity of the polymer solution is 125 mPa s, and when the oil viscosity is 1050 mPa s, the critical value is 205 mPa s. When the viscosity of polymer solution reaches the critical value, for the surfactant–polymer system, a reduction in the oil–water interfacial tension has the same effect as a substantial increase in the polymer solution viscosity; moreover, the joint effect of the sweep efficiency and displacement efficiency can be enhanced. Therefore, for heterogeneous heavy oil reservoirs, the focus should be on improving oil displacement efficiency under certain sweep conditions rather than on expanding the swept volume. The findings of this study can help for better understanding of the selection of displacements agent in heterogeneous heavy oil reservoirs for enhanced oil recovery.

How the wettability of pore surfaces affects supercritical (sc) CO2 capillary trapping in geologic carbon sequestration (GCS) is not well understood, and available evidence appears inconsistent. Using a high-pressure micromodel-microscopy system with image analysis, we studied the impact of wettability on scCO2 capillary trapping during short-term brine flooding (80 s, 8–667 pore volumes). Experiments on brine displacing scCO2 were conducted at 8.5 MPa and 45°C in water-wet (static contact angle θ = 20° ± 8°) and intermediate-wet (θ = 94° ± 13°) homogeneous micromodels under four different flow rates (capillary number Ca ranging from 9 × 10−6 to 8 × 10−4) with a total of eight conditions (four replicates for each). Brine invasion processes were recorded and statistical analysis was performed for over 2000 images of scCO2 saturations, and scCO2 cluster characteristics. The trapped scCO2 saturation under intermediate-wet conditions is 15% higher than under water-wet conditions under the slowest flow rate (Ca ∼ 9 × 10−6). Based on the visualization and scCO2 cluster analysis, we show that the scCO2 trapping process in our micromodels is governed by bypass trapping that is enhanced by the larger contact angle. Smaller contact angles enhance cooperative pore filling and widen brine fingers (or channels), leading to smaller volumes of scCO2 being bypassed. Increased flow rates suppress this wettability effect.

Recently, both core- and pore-scale imbibition experiments have shown non-equilibrium dissolution of supercritical CO2 (scCO2) and a prolonged depletion of residual scCO2. In this study, pore-scale scCO2 dissolution and mass transfer under drainage conditions were investigated using a two-dimensional heterogeneous micromodel and a novel fluorescent water dye with a sensitive pH range between 3.7 and 6.5. Drainage experiments were conducted at 9 MPa and 40 °C by injecting scCO2 into the sandstone-analogue pore network initially saturated by water without dissolved CO2 (dsCO2). During the experiments, time-lapse images of dye intensity, reflecting water pH, were obtained. These images show non-uniform pH in individual pores and pore clusters, with average pH levels gradually decreasing with time. Further analysis on selected pores and pore clusters shows that (1) rate-limited mass transfer prevails with slowly decreasing pH over time when the scCO2-water interface area is low with respect to the volume of water-filled pores and pore clusters, (2) fast scCO2 dissolution and phase equilibrium occurs when scCO2 bubbles invade into water-filled pores, significantly enhancing the area-to-volume ratio, and (3) a transition from rate-limited to diffusion-limited mass transfer occurs in a single pore when a medium area-to-volume ratio is prevalent. The analysis also shows that two fundamental processes – scCO2 dissolution at phase interfaces and diffusion of dsCO2 at the pore scale (10–100 µm) observed after scCO2 bubble invasion into water-filled pores without pore throat constraints – are relatively fast. The overall slow dissolution of scCO2 in the millimeter-scale micromodel can be attributed to the small area-to-volume ratios that represent pore-throat configurations and characteristics of phase interfaces. This finding is applicable for the behavior of dissolution at pore, core, and field scales when water-filled pores and pore clusters of varying size are surrounded by scCO2 at narrow pore throats.