The behavior of two-phase flow through porous media is controlled by flow functions, especially in fractured porous media where the matrix and fracture relative permeabilities are different. Some researchers observed that the fracture relative permeability does not obey the linear (X) model. However, the question of how fracture geometry may affect the fracture relative permeability is not well discussed in the literature. In this study, a series of crude oil-water displacements were performed on an in-house designed 2D fractured porous media with different fracture geometries. The individual fracture and matrix relative permeabilities were obtained from inverse modeling of the experimental data using a black-oil simulator. For the first time, the role of fracture geometry, such as fracture number, orientation, and intersection angle, on fracture relative permeability was examined, and the parameters of Corey’s model for fracture relative permeability with varying geometry were obtained. Results showed that as the fracture number, orientation, and intersection angle increased, fracture relative permeability curves lost up to 50% of their curvature, reaching the linear model. The same modeling approach was applied to extract fracture relative permeability from similar experiments reported in the literature for a different fluid system. Consistent results for fracture relative permeabilities from both sets of experiments confirm the reliability of the assumptions made in simulation models. This study shed light on the impact of fracture geometry on fracture relative permeability, which might aid in developing simulation models of flow through fractured media.

Production of excess undesirable brine, is one of the severe problems in highly heterogeneous and fractured oil reservoirs which are under water based enhanced oil recovery (EOR) methods. Recently, preformed particle gels (PPGs) are proposed and used as a diverting agent to control the conductivity of the fractures. Although numerous studies in the literature report improved structural strength and rheological properties of PPGs in the presence of silica nanoparticles (SNP), the possible effect of SNP concentration on such results have not been investigated in details. In addition the effect of rheological parameters such as structural strength and elastic/viscous modulus on the flow dynamics of the secondary water injection (after replacement of the PPG in the fractures) are less studied and rarely visualized. Furthermore, the possible effect of the presence of water soluble fractions (WSF) of the crude oil in the brine (due to long term interactions between formation water and crude oil) on swelling of particles and strength of the PPG samples are overlooked in most cases. With this aim, in the first step of the present research, four PPG samples with different concentrations of SNP were synthesized and assessed through different bulk and rheological tests. Bulk tests showed that presence of the SNP increases the swelling capacity of the samples, since the gel particles containing 0.4 wt% SNP had the better swelling factor (e.g., 25 in 100 times diluted sea water, 100xdSW) compared to the sample without nano particles (15 in 100xdSW). However further increase in the amount of nano particles to 0.8% and 1.0% decreases the swelling capacity of the PPG particles (24 and 19 in 100xdSW, respectively). It was shown that the type and concentration of ions in the brine, as well as the oil/brine interactions affect the swelling behavior. Absence of water soluble fractions of crude oil in the brine and increasing the salt concentration reduce the swelling capacity of the gel particles. Moreover, presence of WSF can hinder the effect of high salinity in the swelling kinetics of the PPG particles. While WSF in the brine enhances the swelling capacity of PPG particles, Hele-Shaw dynamic plugging tests revealed that the PPG samples swelled using these brines, have reduced resistance against secondary water injection compared to the samples swelled in counterpart brines without WSF. Rheology tests of the PPGs confirmed the significant effect of SNP concentration on the storage and loss moduli. Dynamic tests in the model fracture show that although generally the SNP improved the dynamic strength and plugging performance of the PPG against secondary water injection, only the PPG sample with 0.8 wt% nano silica showed the desirable plugging performance (although its swelling capacity is slightly less than 0.4% SNP gel). This PPG sample creates an extra low permeability porous media in the fracture which due to the proper viscoelastic properties allows very low mobility of water through the fingers created between some particles, with no significant or visible gel washout from the fracture. However in the case of other PPG samples, the injected secondary water pushed out some amount of the gel particles and created a wide high conductive flow path inside the treated fracture. Based on the combination of swelling capacity, rheological strength, and dynamic plugging performance, among the synthesized gels, the one with the 0.8 wt% SNP is the recommended optimal concentration for effective water shut-off of the designed fracture.

In this work, for the first time, we report the size-dependent contact angle and dynamic contact angle patterns of live oil on carbonate substrates coated with superoleophobic and oleophobic PDMS/SiO2 nanofluids in a medium of methane gas at the reservoir conditions. Coupled with the modified Young equation, the sign and magnitude of line tension for the nanocoated carbonate rock/live oil/methane systems are measured. It is demonstrated that for the superoleophobic surface, obeying the constant receding contact angle pattern, the ultra-low contact angle hysteresis (<10 degrees), besides the high static contact angle of the live oil droplet (>150 degrees), imparts a non-stick feature to the rock surface by which the live oil droplets can be effortlessly displaced on the surface with a near zero tilt and are conveniently detached while receding without leaving a trace. In contrast, it is shown that the oleophobic surface, which complies with no receding contact angle pattern, suffers the non-adhesive property due to the high contact angle hysteresis, and thus, the live oil pins firmly to the rock surface. Furthermore, the modeling of size-dependent contact angle behavior on carbonate surfaces with oil-repellent wettability, which is developed based on the numerical approach of the Young-Laplace equation and minimizing the Gibbs free energy, successfully predicts the experimental data with close agreement. We expect this work to offer a more profound understanding of the nature of size-dependent contact angle, contact angle hysteresis, and rock/oil adhesion force for nonwetting surfaces, elucidating their influence on the enhanced oil recovery process.

Reservoir rock typing plays an important role in predicting fluid flow behavior and reservoir management decisions. However, conventional classification techniques, based on static petrophysical properties such as porosity and permeability may not fully reflect the dynamic nature of multiphase flow processes. This study presents the Flow Functions Rock Typing (FFRT) approach, which classifies rock samples based on dynamic flow characteristics derived from co-current spontaneous imbibition experiments, with emphasis on capillary pressure and relative permeability functions. Using ten carbonate core samples, spontaneous imbibition experiments were conducted and history-matched with numerical simulations implemented in COMSOL to extract the corresponding flow functions. The FFRT method successfully identified three distinct rock types (FFRT1 to FFRT3), each corresponding to unique two-phase flow behaviors. Across the identified FFRT classes, systematic trends are observed, whereby samples with higher permeability generally exhibit steeper water relative permeability curves and shifted crossover points, consistent with more favorable water mobility during imbibition. Correspondingly, the capillary pressure curves display decreasing entry pressures and less steep slopes for higher-permeability samples, reflecting differences in pore-scale characteristics within the studied rocks. Moreover, analysis of the imbibition responses suggests the presence of different dominant flow regimes, namely inertial, capillary, and gravity-influenced. Overall, the results demonstrate that FFRT provides a conceptually clear, physics-guided framework for exploring dynamic flow behavior in core-scale experiments. While demonstrated here on a limited air–water carbonate dataset, the approach offers a basis for further investigation of dynamic rock typing beyond purely static petrophysical classifications.

Naturally fractured reservoirs are of significant importance in global oil production. One of the main production mechanisms from these reservoirs is gravity drainage. Previous researches have focused on understanding the effective factors on the oil recovery from blocks and the degree of capillary continuity (block to block interaction). However, the results from these studies have not been consistent in some cases and there are ambiguities in the influence of some of the effective parameters on the dynamic discharge of oil from the matrix block. The purpose of the present study is to comprehensively investigate the impact of the main affecting parameters on oil recovery from the fractured porous media with the implications on the degree of capillary continuity through analysis of the stability of the oil bridges, along with addressing the reason of reported inconsistencies in previous studies. With this aim microfluidics experiments on a realistic rock-based single-block and three-block systems are performed and different parameters including the tilt angle of the blocks, injection rate and aperture of the transverse fracture are investigated. In addition, the realistic approach of aging micromodels allowed to examine the effect of degree of oil-wetness on capillary continuity in different multi block systems, an aspect that had not been explored in previous studies. In the case of multi-block systems, the location, number and stability of the formed liquid bridges and the effect on capillary continuity were examined. It was found that oil recovery from single block decreases at higher tilt angles, while in multi-block systems different trends are observed based on the range of injection rate which is attributed to the number and stability of formed liquid bridges. It was also found that in multi-block systems the increase in injection rate can establish capillary continuity through forming liquid bridges. Furthermore, new analytical relationships are developed in the case of single block porous media under free fall gravity drainage, to predict the downward flow of the liquid level within the fracture and matrix. The findings of this study can be used for enhancing the performance of gas injection strategies in fractured systems.

The formation of a liquid bridge between two adjacent surfaces has a crucial role in many industrial and scientific applications, such as waste disposal management, granular materials, and flow through fractured porous media. Despite numerous studies, the understanding of how the stability and capillary pressure of liquid bridges formed in rough fractures may controlled by the geometrical properties of fracture surface roughness has received limited attention. In this study, a natural fracture profile of a subsurface carbonate rock is analyzed and the geometrical properties of cone-plate roughness models are extracted. Combined with the numerical solution of the Young-Laplace capillarity equation, the liquid bridge capillary pressure and breakup distance in the rough fracture systems are characterized, and more realistic data of fracture capillary pressure and breakup distance of liquid bridges are provided. The results show that increasing the roughness height causes the breakup distance of liquid bridge increases, while the capillary pressure decreases. When, the liquid volume in the fracture is less than 5% and the fracture width is sufficiently thin (<0.2 mm), the liquid bridge capillary pressure is as high as 14 KPa, which is a significant value. In the context of natural fractured reservoirs, where fractures possess different widths and roughness characteristics, a new generalized capillary pressure model is developed, which enables the estimation of capillary pressure for liquid bridges formed in rough-walled fractures. The capillary pressure data of rough fractures presented in this work, may fill a gap in the literature and providing required information for simulating oil recovery in fractured reservoirs.

Significant amounts of residual oil can remain trapped after primary and secondary recovery stages, which can be effectively recovered using tertiary gas injection processes. While tertiary gas injection in water-swept reservoirs has been widely studied, the characterization of tertiary enriched gas injection following secondary lean gas injection remains underexplored. One critical challenge is the lack of gas-oil relative permeability and capillary pressure functions specific to this process, which play a key role in controlling multiphase flow behavior and oil mobilization. To address this gap, a series of coreflood experiments was performed by injecting lean gas followed by enriched gas into a low-permeability carbonate core. The CMG/GEM compositional simulator, coupled with the Design Exploration Controlled Evolution (DECE) history-matching algorithm, was used to match experimental data, including oil recovery, cumulative gas production, and pressure drop. Relative permeability and capillary pressure curves for tertiary enriched gas injection were derived from these simulations. Results showed the ultimate oil recovery increased by 12%. Analysis of ternary diagrams and produced fluid composition indicated that residual oil was mobilized primarily through a combined vaporizing-condensing mechanism. This study demonstrates the potential of tertiary enriched gas injection as an effective recovery strategy for reservoirs subjected to prior lean gas flooding.

Although water injection is one of the most common methods for enhancing the recovery from oil reservoirs, its effectiveness in severely heterogeneous porous media such as fractured rocks, is debatable. Preformed Particle Gel (PPG) treatment is one of the most promising methods which is considered for water shut-off in the near wellbore area or improving the sweep efficiency of the injected water deep in the reservoir. Recognizing the PPG transport mechanisms in fracture, fracture/matrix interactions during and after PPG treatment, and the contributing parameters on such mechanisms, is a prerequisite for designing an effective water shut-off process and possible enhanced oil recovery (EOR). With this aim, the dynamic behavior of PPG samples is studied in two different fractured porous media representing the near wellbore area (dual permeability model) and deep in the reservoir zones (single permeability model). During encroachment of the gel particles in fracture, the dehydration of gel produces a large volume of filtrate which sweeps the oil inside the matrix. PPG particles might go through deformation, shrinkage and/or breakage, before infiltrating into pores of matrix where they form an impermeable cake. The experimental results shows that formation of such cake, is one of the main affecting parameters in the performance of the conformance control and EOR. Additionally, the affecting parameters such as concentration of nano-silica (n-SiO2), width of fracture, particles size, ionic strength of brine and injection rate of gel were examined. The concentration of n-SiO2 affects the gel loss factor (ratio of loss modulus to storage modulus) and hence its encroachment behavior. The gel sample with 1 wt% n-SiO2 has the highest loss factor which makes it more favorable for water shut-off considering lower injection pressure and less volume required for treatment. The water shut-off treatment is more effective in the case of systems with wider fractures. Based on the size of the PPG particles, the plugging mechanisms of the fracture can be either direct plugging, bridge plugging or a combination of both mechanisms, however all the studied samples provided same degree of plugging efficiency in the performed experiments. Swelling the samples in brines with higher salinities reduces the required volume of gel, while the injection pressure remained unaffected. To reduce the required volume of gel, highest possible injection rate is recommended, since the shear thinning rheology of the gel damps increment of injection pressure. In the case of single permeability model, water shut-off treatment reduced the fracture conductivity effectively, so that in the subsequent flooding, the injected brine was diverted toward matrix and the displaced oil was recovered through the fracture. During water flooding stage after gel placement, the withstanding pressure of PPG must be taken into account to avoid gel rupture, movement and washout.

Surfactant injection is a promising method for enhanced oil recovery (EOR) due to its effective micro-displacement mechanisms. However, understanding the interaction of a surfactant solution with heavy oil in porous media is neither straightforward nor well understood, particularly in heterogeneous systems. By enabling in-situ real-time monitoring of flow transport, microfluidic studies have provided novel insights into the underlying multiphase physics of flow at the pore scale. This paper examines the two-phase displacement efficiency of a new surfactant in layered-fractured porous microfluidic patterns, a topic seldom discussed in the literature. To evaluate the performance of the proposed surfactant, we considered several heterogeneous media with varying layer and fracture geometrical characteristics, quantifying displacement efficiency for each case. Based on the analysis of pore-scale snapshots, it was inferred that the primary mechanisms responsible for EOR during surfactant flooding into heavy oil include pore wall transportation, emulsifications, the deformation of residual oil, inter-pore or intra-pore bridging, and wettability alteration. Macroscopic displacement experiments revealed that the width of the swept area from surfactant injection significantly exceeded that of water injection, resulting in a substantially higher oil recovery. Furthermore, it was demonstrated that the direction of fluid flow in relation to fracture orientation plays a critical role in the dynamics of surfactant solution movement and, consequently, the ultimate oil production.

The stability of liquid bridges formed between two solid substances plays an important role in many industrial applications, including oil–water separation, granular materials, offset printing and oil recovery from fractured reservoirs. Despite numerous studies, fundamental understanding of how slipping and pining regimes of contact angle, may affect the stability of stretching liquid bridges formed between two solid substances is not discussed in the available literature. In this study, the impact of slipping and pining regimes of contact angle on the stability of the dynamic liquid bridge was investigated. To do that, a Computational Fluid Dynamic (CFD) model was developed and used to analyze liquid bridge stability/evolution in a smooth horizontal fracture for static and dynamic conditions. The models' validities were checked by comparing the models' results with the experimental data. In the static modeling part, a new expression for predicting the rupture distance of liquid bridge was proposed which could be applied for a wide range of liquid bridge volume, contact angle, and Bond number. The power of the liquid bridge volume in the expression depends on both the liquid bridge volume and surface wettability. In the dynamic modeling part, as an interesting result, it was observed that the variations of the rupture distance with Weber, Capillary, and Bond numbers strongly depend on the regimes of contact angle, and the rupture distance for the slipping regime is greater than that of the pinning regime by a factor of 1.02–1.32 depending on liquid bridge volume and surface wettability. The results also showed that the rupture distance approaches asymptotic values for the Bond, Weber, and Capillary numbers equal or less than 10-2, 10-4, and 10-5, respectively. The results of this study contribute to better understanding of how regimes of contact angle would affect liquid bridge stability in smooth horizontal fractures and could improve our understanding of interfacial flow in fractured rocks.

Recently, super gas wet and gas wet surfaces have been extensively attended in petroleum industry, as supported by the increasing number of publications in the last decade related to wettability alteration in gas condensate reservoirs. In many cases, contact angle measurement has been employed to assess the wettability alteration. Even though contact angle measurement seems to be a straightforward approach, there exist many misuses of this technique and consequently misinterpretation of the corresponding results. In this regard, a critical inspection of the most recent updated concepts and the intervening parameters in the contact angle based wettability evaluation of liquid-solid-gas systems could aid to provide some remediation to alleviate this problem. To this end, this work presents a survey on the accurate terms and rigorous protocols based on the community of surface science and chemistry. As a preliminary step, advancing, receding, static, and the most stable contact angle terminology are defined. The study is followed by the definition of the contact angle hysteresis effect. The application of surface free energy in the selection of the best gas wet agent is then analyzed. Afterward, the impact of the size-dependent behavior of drop on contact angle is discussed. Finally, a sessile drop experiment is explained to achieve the defined parameters. For future contributions to petroleum industry journals, like this journal, this work could offer an easy use of the conceptual framework for analyzing the results and comparative evaluations in chemical wettability modifier agents.

We have used the Maxwell–Stefan diffusion theory to model the mass transfer between tertiary-injected gas and residual oil blocked by water, in order to predict the time required for the rupture of the water barrier due to oil swelling. We have also designed and conducted a set of visualization micromodel experiments on various pure and multicomponent oil–gas systems to measure the water rupture time in tertiary gas injection processes. The experimental results show that the initial pressure and dimensions of the system, the oil and gas composition, and the gas solubility in water control the oil swelling process. The experimentally measured rupture times are then employed to evaluate the reliability of the model and to compare its accuracy with that of a similar one using classical Fick's law. Our modeling results show that both models are able to estimate the water rupture time for pure systems with an acceptable precision. As for multicomponent mixtures, however, only the Maxwell–Stefan theory is capable of modeling the molecular diffusion process correctly and yields values close to reality, while the use of Fick's law would lead to erroneous results. Deficiency of the latter model becomes more acute when the diffusion direction in reality is contrary to what the model indicates, which leads to failure in calculating any value for rupture time at all for these cases.

The present article aimed to examine the pore-scale examination of a fluid capability to block pores and fractures deduced by return permeability and the blocking ability of a novel lightweight Colloidal Gas Aphron Nano-Fluid (CGANF) in heterogeneous fractured/un-fractured porous medium. Silica (S) and fumed silica (FS) nanoparticles, Sodium Dodecyl Sulfate (SDS) anionic surfactant, and Xanthan Gum (XG) bio-polymer were employed for following up CGANF bubbles' movements in incongruous micro-models’ inclusive crack. The transparent nature of the glass micro-model provides an intuition into the lenticular behavior of CGANF bubbles in the heterogeneous porous media. Differential pressure analysis through porous media during experiments demonstrated that opposition to the stream of CGANF bubbles increased as more CGANF fluid was injected. Also, the lamella division mechanism generated more small bubbles resulting in increasing differential pressure across porous micro-models. Contrasted to bigger CGANF bubbles, smaller CGANF bubbles had lesser movability. Therefore, they were key factors for blocking pores and throats of porous media and changed the orientation of bigger bubbles in cracks toward the matrix. Observations revealed that CGANF micron-bubbles built up through the porous media could set up an impressive snag to control loss of filtrate, and permeability of models was reverted almost to its primary permeability when saturation fluid was reinjected into micro-models. For the detailed analysis in this study, the maximum percentages of reverted permeability for fractured and un-fractured non-uniformed micro-models were attained 91.81% and 90.70%, respectively. Also, by increasing XG concentrations from 0.286 to 0.571% w/v, return permeability percentage increased from 84.4% to 87.4%. There was an optimum concentration of nanoparticles at 0.0571% w/v of silica and fumed silica, and consequently, returned permeability and infusion pressure of CGANF fluid reached their maximum values. Moreover, the stability of the CGANF fluid increased to 8.15% and 12.6% by adding silica and fumed silica nanoparticles, respectively, to the CGA fluid formulation without nanoparticles. This article presents a novel insight into porous media for analyzing blockage capability and controlling porous media damage created via CGANF-based fluids in non-uniformed environments.

In waterflooding process, the time for breakthrough of injecting fluid into a production well is of great importance. Predicting this time helps in designing reservoir development plan. Due to uncertainties in reservoir characterization, estimating the breakthrough is not easy, so alternative methods to estimate quickly the breakthrough time is useful. The percolation method uses limited available reservoir data to predict the breakthrough time distribution, and it may be used for engineering applications. However, implementation of this to real reservoirs requires some adjustments. The aim of this study is to show how percolation approach can be used to real problems. In particular, the effects of permeability contrast between the reservoir and non-reservoir parts in the model are investigated. In order to use the breakthrough scaling function to more realistic reservoir models, a dimensionless breakthrough time was used. The analysis of the breakthrough time of models with zero permeability background (tk=0) and such time for the case of non-zero permeability background (tk=αk) shows a linear dependency which can be used to find breakthrough time distribution. Hence, this correction extends the applicability of the percolation method for predicting breakthrough time when permeability of the system background is not zero.

The creation of surfaces with various super nonwetting properties is an ongoing challenge. We report diverse modifications of novel synthesized zirconia-ceria nanocomposites by different low surface energy agents to fabricate nanofluids capable of regulating surface wettability of mineral substrates to achieve selective superhydrophobic, superoleophobic-superhydrophilic, and superamphiphobic conditions. Surfaces treated with these nanofluids offer self-cleaning properties and effortless rolling-off behavior with sliding angles ≤7° for several liquids with surface tensions between 26 and 72.1 mN/m. The superamphiphobic nanofluid coating imparts nonstick properties to a solid surface whereby liquid drops can be effortlessly displaced on the coating with a near-zero tilt and conveniently lifted off using a needle tip, leaving no trace. Further, the superamphiphobic surface demonstrates good oil repellency toward ultralow surface tension liquids such as n-hexane and n-heptane. The superoleophobic-superhydrophilic surface repels oil droplets well regardless of whether it is in the air or underwater conditions. In addition, reaping the benefits of the ZrO2-CeO2 nanocomposites' photocatalysis feature, the superoleophobic-superhydrophilic coating exhibits self-cleaning ability by the degradation of color dyes. Modification of the wettability of substrates is carried out by a cost-effective and facile solution-immersion approach, which creates surfaces with hierarchical nano-submicron-scaled structures. The multipurpose coated surfaces have outstanding durability and mechanical stability. They also resist well high-temperature-high-pressure conditions, which will provide various practical applications in different fields, including the condensate banking removal in gas reservoirs or the separation of oil/water mixtures.

One of the basic challenges during drilling horizontal wellbores is the damage induced by invasion of mud filtrate into the formation. Addition of nanoparticles to drilling fluids has been recognized as a measure of control and reduction of filtrate invasion, which is the primary mechanism of the aforementioned formation damage. Despite notable advances in composing Nano-enhanced drilling fluids, the role of nanoparticle hydrophobicity on performance of the fluids has not been well studied. This study is based on a combined experimental-numerical methodology. In the experimental section, a procedure to find the optimum composition of Nano-enhanced water-based samples, containing nanoparticles of hydrophilic/hydrophobic silica and lipophilic clay to minimize the formation damage associated with mud circulation is recommended. The main idea was to investigate the effect of hydrophobicity of nanoparticles on damage reduction and furthermore, discover how other properties such as types/concentration of nanoparticles/micro-sized additives, temperature and pressure would affect functionality and characteristics of drilling fluids. In order to more accurately and practically investigate any probable enhancements in performance of fluid samples a particular radial filtration setup was designed and used; then, functionality of mud samples was examined on grain packed porous media at radial flooding flow condition. Results revealed that samples containing 0.2 wt. % hydrophobic nanosilica had the best functionality with returned permeability of 68.4% and 51.1% for the cases of water saturated and oil saturated porous media, respectively. In the modeling section, mass balance and momentum equations were solved simultaneously by using elapsed time data. Permeability as well as thickness of mud cake formed on the wellbore wall were evaluated and compared for different Nano-enhanced mud samples. Results showed that nano-enhanced drilling fluid samples generated thinner mud cakes with lower permeability values during quite shorter period of time. Results of this work might be helpful to better understand the behavior of nano-enhanced drilling fluids in radial porous systems at different conditions of nanoparticles hydrophobicity and applicable to minimize the induced formation damage during drilling of the horizontal section of a production well.

Forced gas oil gravity drainage (FGOGD) is one of the main driving mechanisms in fractured porous media. Understanding the role of viscous force for matrix oil recovery by gas injection into fracture network is of crucial importance. Despite the importance of FGOGD as a major oil recovery mechanism in fractured porous media, limited research reports exist in literature. We utilized a visual glass micromodel to investigate this mechanism experimentally. A model comprised of four matrix blocks surrounded by fractures was used to replicate the porous media. The system was saturated with crude oil. Carbon dioxide was injected at different rates to investigate the interaction of gravity, capillary, and viscous forces. Recovery curves and microscopic visualization of fluid flow in this transparent model showed that injection rate affects the ultimate recovery of matrix substantially. The observations demonstrated that matrix recovery under gas injection under filled fracture condition recovers oil at higher rate with respect to free fall gravity drainage, but the ultimate oil recovery is the same. Furthermore, the ultimate recovery factor could be maximized when the gas injection started just as the oil level was reaching the capillary threshold height blocks. There is an optimum injection rate for maximizing oil recovery in fracture-matrix systems. This article sheds more light on the role of viscous forces in gas invaded zone of naturally fractured porous media.

Surfaces with special wettability have aroused lots of attention due to their broad applications in many fields. In this work, we systematically report selective and various fabrications of nanofluids based on readily available materials such as SiO2 nanoparticles and polydimethylsiloxane to create superhydrophobic, superoleophobic, superhydrophilic/superoleophobic, and underwater superoleophobic coatings. The efficiency of prepared coatings is investigated on mineral rock plates as porous substrates via the straightforward and cost-effective solution-immersion technique. The static water contact angle of 170 degrees, effortless bouncing of water droplets, and self-cleaning property with a near zero tilt of the solid surface are signs of a high-performance superhydrophobic surface treated with the polydimethylsiloxane-modified silica nanofluid. The superamphiphobic nanofluid coating endows a non-adhesive feature to the rock surface by which the water and oil droplets can be freely moved on the surface with negligible tilt and are easily detached by a needle tip without leaving a trail. What is more, the superamphiphobic surface provides excellent anti-fouling and self-cleaning properties, along with convenient rolling-off behavior with sliding angles <= 8 degrees for various oily liquids. Also, the obtained superhydrophilic/superoleophobic surface exhibits dual superoleophobicity both in air and underwater. These diverse coatings can be used on different substrates, which notably expand the scope of applications. As a case, we employed the superhydrophilic/superoleophobic coating on a stainless-steel mesh for oil-water separation. The separation efficiency of above 99% for various oil-water mixtures confirms the superior oil-shielding and water-affinity properties of the coating. All of the abovementioned advantages, combined with significant chemical and mechanical stability and high-pressure-high-temperature resistance of the treated surfaces, indicate that the prepared multifunctional coatings will hold great potential in a variety of practical and industrial applications.

This paper focuses on developing a new method that represents user-accessible correlation for estimation of water-based nanofluids viscosity. For this, an evolutionary algorithm, namely Gene Expression Programming (GEP), was adapted based on a wide selection of literature published databanks including 819 water-based nanofluids viscosity points. The developed model utilized the base fluid viscosity as well as volume fraction and size of the nanoparticles as the inputs of the model. Several statistical parameters integrated with graphical plots were employed in order to assess the accuracy of the proposed GEP-based model. Results of the evaluation demonstrate fairly enough accuracy of the developed model with statistical parameters of AARD%=11.7913, RMSE=0.3567, and SD=0.1851. Furthermore, the trend analysis indicates that the GEP calculated points satisfactorily follow the trend of the nanofluid viscosity variation as a function of different model inputs. To provide more verification, the proposed GEP model was compared with some literature theoretical and empirical correlations leading to the supremacy of the developed model here. The applied sensitivity analysis reveals that the highest impact value is assigned to the volume fraction of the nanoparticle. Moreover, the outliers detection by Williams’ technique illustrates that about 96.5% of the GEP estimates are in the applicability domain resulting in the validity of the proposed model in this study. At last, the results of this study demonstrate that the new method here outperforms other literature published correlations from the standpoint of accuracy and reliability.

In this research, a new diffusion mechanism called "double cross-phase diffusion" is introduced and applied to simulate the non-equilibrium gas injection process into fractured rocks. This new mechanism represents additional multicomponent gas diffusion into the crude oil through the water phase, existing in porous media as initial water saturation. Therefore, a lab-scale simulator, by implementing the generalized Fick's law of multicomponent diffusion, is developed and used for predicting the experimental data of oil recovery during CO2 injection in chalk fractured rocks in the presence of initial water saturation. The results revealed a significant difference in the oil recovery predicted by the model when the double cross-phase diffusion mechanism is considered. The transient behavior of produced oil composition, predicted by the simulation model, is matched well with the experimental data. The portion of active oil recovery mechanisms in the system has been evaluated for the first time and it was observed that the molecular diffusion mechanism induced 75.4% of the total oil transfer rate in the initial time oil recovery, in which 23.1% of this value was supplied by the double cross-phase diffusion mechanism, which is an interesting finding. Results of sensitivity analysis showed that by increasing the initial water saturation, the impact of the double cross-phase diffusion mechanism on oil recovery increases. In contrast, the transferred rate by the diffusion mechanism decreases from 85.4% to 60.8% when matrix permeability increases from 0.1 to 10 mD. The results of this work illustrate that the double cross-phase diffusion mechanism introduced in this study plays a significant role in the simulation results since the water is responsible for accelerating the diffusivity of CO2 into the crude oil and, in consequence, increasing the oil recovery.