Permeability Oil Research Articles

Clove Oil Endorsed Transdermal Flux of Dronedarone Hydrochloride Loaded Bilosomal Nanogel: Factorial Design, In vitro Evaluation and Ex vivo Permeation

The goal of this study was to develop a bilosomal gel formulation to enhance transdermal permeability of dronedarone hyrdrochloride (DRN) which suffers from poor oral absorption and limited bioavailability. To overcome this obstacle, bilosomes were successfully prepared using 23 full-factorial design. Span®40, cholesterol, sodium deoxycholate (bile salt), clove oil (permeability enhancer), and either Tween® 60 or Tween® 80 (edge activator) were used in bilosome preparation by ethanol injection method. In this design, independent variables were X1, edge activator type; X2, edge activator amount (mg); and X3, permeability enhancer concentration (% w/v). Optimal formula (B2) of the highest desirability of (0.776) demonstrated minimum vesicle size (VS) of 312.4 ± 24.42 nm, maximum absolute value of zeta potential (ZP) − 36.17 ± 2.57 mV, maximum entrapment efficiency (EE %) of 80.95 ± 3.01%, maximum deformability Index (DI) of 8.24 ± 1.26 g and maximum drug flux after 12 h (J12) of 21.23 ± 1.54 µg/cm2 h upon ex vivo permeation study. After 12 h, 70.29 ± 6.46% of DRN was released from B2. TEM identification of B2 showed spherical shaped nanosized vesicles which were physically stable for 3 months at different temperatures. B2 was incorporated into carboxymethylcellulose gel base for easiness of dermal application. B2 gel demonstrated good physical properties, non-Newtonian psuedoplastic flow, and enhanced release (57.0 ± 8.68% of DRN compared to only 13.3 ± 1.2% released from drug suspension after 12 h) and enhanced skin permeation.Graphical abstract

Development and Evaluation from Laboratory to Field Trial of a Dual-Purpose Fracturing Nanofluid: Inhibition of Associated Formation Damage and Increasing Heavy Crude Oil Mobility.

This study aims to develop and evaluate fracturing nanofluids from the laboratory to the field trial with the dual purpose of increasing heavy crude oil mobility and reducing formation damage caused by the remaining fracturing fluid (FF). Two fumed silica nanoparticles of different sizes, and alumina nanoparticles were modified on the surface through basic and acidic treatments. The nanoparticles were characterized by transmission electron microscopy, dynamic light scattering, zeta potential and total acidity. The rheological behavior of the linear gel and the heavy crude oil after adding different chemical nature nanoparticles were measured at two concentrations of 100 and 1000 mg/L. Also, the contact angle assessed the alteration of the rock wettability. The nanoparticle with better performance was the raw fumed silica of 7 nm at 1000 mg/L. These were employed to prepare a fracturing nanofluid from a commercial FF. Both fluids were evaluated through their rheological behavior as a function of time at high pressure following the API RP39 test, and spontaneous imbibition tests were carried out to assess the FF’s capacity to modify the wettability of the porous media. It was possible to conclude that the inclusion of 7 nm commercial silica nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation without altering the rheological properties of the system. Displacement tests were also performed on proppant and rock samples at reservoir conditions of overburden and pore pressures of 3200 and 1200 psi, respectively, while the temperature was set at 77 °C and the flow rate at 0.3 cm3/min. According to the effective oil permeability, a decrease of 31% in the damage was obtained. Based on these results, the fracturing nanofluid was selected and used in the first worldwide field application in a Colombian oil field with a basic sediment and water (BSW%) of 100 and without oil production. After two weeks of the hydraulic fracture operation, crude oil was produced. Finally, one year after this work, crude oil viscosity and BSW% kept showing reductions near 75% and 33%, respectively; and having passed two years, the cumulative incremental oil production is around 120,000 barrels.

EXPERIENCE OF USING SIMULTANEOUS-SEPARATE DOWNLOADS AT THE AKSHABULAK TSENTRALNY DEPOSIT

The traditional joint injection of water into several reservoirs with different permeability does not control bottom hole pressures and water flow for each of the reservoirs (by their current geological parameters), which leads to uneven watering of oil deposits. As a result, advanced watering of highly permeable oil reservoirs occurs, the degree of coverage decreases, uneven impact, and the development of each of the reservoirs with different reservoir properties, namely, permeability occurs. In order to reduce capital costs for drilling a new injection well in multi-layer fields, one injection well accounts for more than two perforated reservoirs of heterogeneous permeability to maintain reservoir pressure. The article describes the successful experience of implementing simultaneous-separate injection and analyzes the effectiveness of implementing the technology of simultaneous-separate injection using the example of the M-II-1 horizon of the Akshabulak Central field. Among the successfully conducted experiments, there is an increase in oil recovery, cost savings due to the effectiveness of the technology, and the absence of any complications during repair work. However, also, there are disadvantages: a decrease in injectivity for individual choke due to contamination of the internal section and an increase in injectivity due to wear of the choke, difficulties in assessing the depletion of separate layers due to the insufficient number of measurements of the inflow profile at production wells. For better results in the future, it is planned to redistribute the history of production across reservoirs at production wells on a capacitive-resistive model (CRM) using neural network technologies, using the account of PLT studies at production wells, and distributed injection across reservoirs at injection wells.

Study of the water displacing oil process in low permeability porous media based on digital rock technology

Unconventional oil has played increasingly important roles for the sustainable development of human society. Understanding the two-phase displacement mechanism in low permeability porous media is therefore essential for the efficient development of unconventional reservoirs. In this study, the water displacing oil process and characteristics in low permeability cores are numerically investigated based on digital rock technology (DRT). The complex internal structure of the low permeability core is directly constructed based on micro-CT images and the pore-scale two-phase displacement behavior is mechanistically studied by solving the Navier-Stokes equations which incorporate the interfacial tension (IFT) and wettability effect. The oil recovery rate obtained from the simulation results agrees well with that obtained from the experimental results under the same pressure drop condition. Parameter studies on the effect of the displacement pressure, IFT, and fluid-rock wettability on the oil recovery ratio are further performed. The numerical results show that the micro-throats in the rock have a significant impact on the recovery ratio. Larger displacement pressures can overcome the capillary force in the micro-throats, thus enhancing the oil recovery due to the expanded sweep region of the displacing fluid in the core spaces. IFT and wettability affect the magnitude and direction of the capillary force in the pore-throats, and a smaller IFT and a higher wetting angle can lead to a higher displacement efficiency. More specifically, it is revealed changing the pore wettability from oil-wet to water-wet could improve the oil recovery ratio significantly. In addition, a numerical simulation of the nanoparticle solution displacement process has been performed to study the synergistic effect of IFT reduction and fluid-rock wettability improvement on oil recovery enhancement. It is demonstrated that DRT can substantially apply in mechanistical studies of the displacement process. in low permeability porous media. The findings of this study can help better understanding of the water displacing oil mechanisms in the complex pore scale geometries and thereby contribute to the low permeable oil recovery practices.

Relative permeability estimation of oil−water two-phase flow in shale reservoir

Oil−water two-phase flow is ubiquitous in shale strata due to the existence of connate water and the injection of fracturing fluid. In this work, we propose a relative permeability model based on a modified Hagen−Poiseuille (HP) equation and shale reconstruction algorithm. The proposed model can consider the nanoconfined effects (slip length and spatially varying viscosity), oil−water distribution, pore size distribution (PSD), total organic matter content (TOC), and micro-fracture. The results show that the increasing contact angles of organic matters (OM) and inorganic minerals (iOM) increase the relative permeability of both oil and water. As the viscosity ratio increases, the relative permeability of oil phase increases while that of water phase decreases, due to the different water−oil distribution. The effective permeability of both oil and water decreases with the increasing TOC. However, the relative permeability of water phase increases while that of oil phase decreases. The increasing number and decreasing deviation angle of micro-fracture increase the effective permeability of oil and water. However, micro-fracture has a minor effect on relative permeability. Our model can help understand oil−water two-phase flow in shale reservoirs and provide parameter characterization for reservoir numerical simulation.

Effect of Interfacial Tension on Relative Permeability Curves Obtained by Considering Surfactant Adsorption and Diffusion

Abstract To consider the effect of adsorption and diffusion of surfactant on relative permeability, a method for estimating the relative permeability was developed by matching production data obtained through an unsteady-state core flooding experiment and numerical simulation. After the robustness of the method was proven, the necessity of considering surfactant adsorption and diffusion in calculating the relative permeability was proven. Compared with relative permeability curves obtained by neglecting surfactant adsorption and diffusion, the average error of the relative permeability curve obtained by considering surfactant adsorption and diffusion decreases from 11.5% to 3.5% for the oil phase and from 13.1% to 4.2% for the aqueous phase. Finally, the effects of interfacial tension (IFT) on relative permeability curves obtained by considering surfactant adsorption and diffusion were studied. The results show that surfactant adsorption and diffusion affect the relative permeability but not the change in the relative permeability curves for varying IFT. The individual relative permeability curve does straighten with decreasing IFT. As the IFT decreases in a semilog plot, the relative permeability values at the equal-permeability point (i.e., the same relative permeability for oil–water) and residual oil endpoint increase following a logistic function and an exponential function, respectively.

Three-dimensional visualization of oil permeation in rice crackers and evaluation of changes in texture

Three-dimensional visualization of oil permeation in rice crackers and evaluation of changes in texture

Natural Stones with a Self-Cleaning Surface via Self-Assembled Monolayers

Heritage buildings and monuments are mostly made from natural stone, which undergoes irreversible decay under outdoor conditions. The main reason for the contamination, degradation, and cracking of natural stones is water and oil permeation. Hence, modifications on stones rendering their surface self-cleaning are effective for stone protection. Reported in this paper is the development of a bionic approach to enabling self-cleaning stone surface via growing self-assembled polydopamine (PDA) as the adhesive layer on the stone surface, followed by depositing Al2O3 nanoparticles derivatized by self-assembled monolayers of a fluorophosphonic acid (FPA). This approach ensured a robust surface modification that realized superhydrophobicity, as demonstrated on natural marbles, Hedishi, and Qingshi. The surface modification was thermally stable up to 400 °C.

Prediction of reservoir key parameters in ‘sweet spot’ on the basis of particle swarm optimization to TCN-LSTM network

In oil reservoirs, the sweet spot is found that the well could be positioned quickly and accurately, the drilling rate and the oil-gas production are increased, development cost is reduced. Among them, sorting, granularity and porosity are important factors to evaluate whether the exploration area is a sweet spot. A low permeability oil reservoir is taken as the research object, this paper mainly focuses on the prediction of the above evaluation parameters. In order to solve this problem, this paper proposed a new deep learning hybrid model. The model is constructed based on temporal convolutional network (TCN) and long short-term memory network (LSTM). Firstly, the influence of logging parameters on the prediction of evaluation indexes is analyzed. Secondly, the model is used to predict the screened sequence data. In the process of model construction, particle swarm optimization (PSO) is used to optimize the global hyperparameters, and finally the prediction model is obtained. The model is compared with TCN algorithm, traditional machine learning and empirical formula. This model improves the prediction accuracy of reservoir evaluation parameters in low permeability oilfield.

Superoleophilic-Hydrophobic Kapok Oil Sorbents via Energy Efficient Carbonization

ABSTRACT High oil sorption, dynamic oil/water selectivity and oil retention are essential for advanced materials to remediate offshore oil spills. In this context, superoleophilic-hydrophobic kapok bundles, synthesized via a simple, one-step and energy efficient carbonization (300°C), were investigated as effective oil sorbents. It was shown that the surface roughness and intrinsic graphite phase of the kapok bundles were tunable by varying the carbonization temperature, thereby enhancing their oil sorption and retention. Lumen preservation enables the carbonaceous kapok bundles to exhibit tunable oil sorption capacities of 34.0 g/g – 95.5 g/g for various types of oil, unrivaled among other oil spill recovery methods. The origin of oil permeability into lumen is attributed to nanopores observed for the first time on the carbonaceous kapok fibers. The kapok bundles selectively absorbed oil slick under vigorous water vortex and demonstrated distinctly high oil retention of 100% under gravitation force. Multiple oil sorption-desorption and compression cycles (up to 15 times) demonstrate a considerable promise of the carbonaceous kapok bundles for high reusability with low environmental impact.

A solar-heated antibacterial sodium alginate aerogel for highly efficient cleanup of viscous oil spills

Hypothesis. Major oil spills highlight the need for environmentally responsible and cost-effective recovery technologies. However, challenges remain for heavy oil spill recovery because of its high viscosity and low fluidity. To achieve this goal, an ecofriendly bio-based aerogel with efficient photothermal conversion ability was developed as a novel absorbent to achieve the fast removal of heavy oil spill by reducing the oil viscosity.Experiments. From the renewable and abundant raw material sodium alginate (SA), hydrophobic and antibacterial SA/graphene oxide/ZIF-8 aerogel (SAGZM) was successfully fabricated via freezing-drying and chemical vapor deposition (CVD) technique. A series of characterization and tests, including aerogel structure, selective wettability, photothermal conversion ability, crude oil removal capability, and antibacterial ability, have been investigated in detail. SAGZM aerogels have rich pore structure, high porosity, excellent mechanical properties, and better photothermal conversion efficiency.Findings. Under sunlight illumination, the recovery ability of SAGZM for heavy crude oil was investigated through infrared thermal imaging, oil permeability behavior analysis, and the continuous absorption for crude oil. In addition, these results are well supported by the theoretical liquid absorption coefficient. This study indicates that SAGZM is highly efficient in in situ regulating oil viscosity through its remarkably photothermal conversion capability. Importantly, SAGZM possesses an excellent antibacterial ability that is often neglected in the design of environmentally friendly materials in extending its service life. The findings of this work not only provide an eco-friendly bio-based aerogel material but also demonstrate that the photo-responsive SAGZM is efficient in heavy crude oil absorption. The proposed solar-heated SA-based aerogel provides a sustainable approach and material to solve the recovery problem of viscous crude oil spills.

Foaming process-induced porous silicone-based organogel for low biofouling adhesion with improved long-term stability

Smart lubricant-infused surfaces (LIS) are expected to bring breakthroughs in anti-fouling materials due to their excellent anti-biofouling performance, but the challenges still remain in developing durable LIS. Herein, the structure of LIS is systematically designed, and realized by an inspiration of foaming process, thereby a large lubricant storage capacity and self-replenishing silicone-based organogel coating with improved long-term stability was prepared. The surface of LIS is constructed of micropores, many independent cavities are built inside, and the bottom is bonded to substrate without defects, which is designed to increase the surface lubricant layer stability, lubricant storage capacity and the adhesion to substrate, respectively. Relying on the well-designed structure and the good permeability of silicone oil in PDMS, the lubricant storage capacity reaches 0.2 g/cm2, and the lubricant lost on surface is well replenished from the lubricant stored inside, which makes the local surface damage almost repair within 60 min, and the lubricant retention rate still remains 85% under the 15-day seawater scouring. Further, due to its good stability, after 84 h of bacterial fouling and 25 days of algal fouling, only a few bacteria and algal adhered to the LIS surface, showing an anti-biofouling efficiency close to 99.5%. These design theories, fabricating methods and materials could provide ideas for the development of advanced smart antifouling materials.

A numerical study of the effects of temperature and injection velocity on oil-water relative permeability for enhanced oil recovery

The paper quantitatively explore the influence of injection rate and temperature on oil-water relative permeability curves during hot water flooding operations in a porous medium flow. ANSYS-CFD was used to construct a numerical model of hot-water injection into an oil saturated sandstone core sample. The modelling technique is based on the Eulerian-Mixture model, using a 3D cylindrical core sample with known inherent permeability and porosity. Injection water at 20 °C was injected into a core sample that was kept at 63 °C and had 14-mD permeability and 26% porosity. For the investigation, three distinct injection rates of 2.9410–6 m/s, 4.41 × 10−6 m/s, and 5.88 × 10−6 m/s were utilised. Furthermore, same injection procedures were repeated under the same conditions, but the core temperature was changed to 90 °C, allowing us to quantify the influence of temperature on the relative permeability curves of oil-water immiscible flow.The results of this study show that the relative permeability of oil is strongly influenced by flow, while the effect of the relative permeability of water is negligible. In addition, the flow rate influences the residual oil and water saturation, as well as the associated effective permeability. From 20 to 90 °C there is little sensitivity to relative permeability or temperature. This study does not provide proof that temperature effects do not exist with genuine reservoir fluids, rocks, and temperature ranges. However, this study has demonstrated the feasibility of utilising CFD approaches to estimate fluid relative permeability, as well as the combined influence of temperature change and flow rate on relative permeability, with the potential for considerable cost-time advantages.

Research on the Depletion and Recovery Characteristics of Fault-Karst Reservoirs

A fractured-vuggy carbonate reservoir is a special reservoir formed by long-term physical, chemical, and geological processes. Its reserves are large in scale and widely distributed, showing the characteristics of free flow-seepage coupling. Conventional simulation is usually simplified by equivalent permeability, which cannot reflect the actual development characteristics. Given this, the flow in caves and fractures is treated with free flow, using the Navier–Stokes equation. The seepage simulation is used for other areas, and the Darcy formula is used. Finally, the simulation results are obtained by coupling, and the influence of oil production speed, fracture-cavity size, fracture-cavity location, dynamic viscosity, permeability, and other factors on bottom pressure is analyzed to effectively guide the field development. The results show that the production pressure of fractured-vuggy reservoirs diffuses from the central fractured-vuggy area to the surrounding matrix, and the pressure increases from the fractured-vuggy area to the surrounding matrix. The flow velocity in the seepage area is relatively stable and flows gently into the middle fracture cavity from all directions. There will be eddy current in the free-flow area. Different factors have different effects on the development. The oil production speed and oil dynamic viscosity are positively correlated with it, while the formation permeability is negatively correlated with it. The size and location distribution of fracture cavity will also have a certain impact. Simulation in advance can effectively avoid some reservoir development problems.

Preparation and Properties of Pea Starch/ε-Polylysine Composite Films.

The composite films comprising pea starch (St) and ε-polylysine (PL) as the matrix and glycerol and sodium alginate as the plasticizers were investigated. The rheological properties, mechanical properties, Fourier transformed infrared spectroscopy, water vapor permeability (WVP), oil permeability, microstructure, thermogravimetry (TGA), and antimicrobial properties of the composite films were analyzed. The properties of the composite films with different mass ratios of St/PL varied significantly. First, the five film solutions were different pseudoplastic fluids. Additionally, as the mass ratio of PL increased, the tensile strength of the blends decreased from 9.49 to 0.14 MPa, the fracture elongation increased from 38.41 to 174.03%, the WVP increased, and the oil resistance decreased substantially. The films with a broad range of St/PL ratios were highly soluble; however, the solubility of the film with a St/PL ratio of 2:8 was reduced. Lastly, the inhibition of E. coli, B.subtilis, and yeast by the films increased with increasing mass ratios of PL, and the inhibition of B.subtilis was the strongest.

Thermophysical Properties of Nanofluid in Two-Phase Fluid Flow through a Porous Rectangular Medium for Enhanced Oil Recovery.

It is necessary to sustain energy from an external reservoir or employ advanced technologies to enhance oil recovery. A greater volume of oil may be recovered by employing nanofluid flooding. In this study, we investigated oil extraction in a two-phase incompressible fluid in a two-dimensional rectangular porous homogenous area filled with oil and having no capillary pressure. The governing equations that were derived from Darcy’s law and the mass conservation law were solved using the finite element method. Compared to earlier research, a more efficient numerical model is proposed here. The proposed model allows for the cost-effective study of heating-based inlet fluid in enhanced oil recovery (EOR) and uses the empirical correlations of the nanofluid thermophysical properties on the relative permeability equations of the nanofluid and oil, so it is more accurate than other models to determine the higher recovery factor of one nanoparticle compared to other nanoparticles. Next, the effect of nanoparticle volume fraction on flooding was evaluated. EOR via nanofluid flooding processes and the effect of the intake temperatures (300 and 350 K) were also simulated by comparing three nanoparticles: , , and . The results show that adding nanoparticles (<5 v%) to a base fluid enhanced the oil recovery by more than 20%. Increasing the inlet temperature enhanced the oil recovery due to changes in viscosity and density of oil. Increasing the relative permeability of nanofluid while simultaneously reducing the relative permeability of oil due to the presence of nanoparticles was the primary reason for EOR.

Perturbative-Integro-Differential Solution for the Nonlinear Hydraulic Diffusivity Equation for Infinite-Acting-Oil Flow in a Permeability-Pressure-Sensitive Reservoir

Summary The nonlinear hydraulic diffusivity equation (NHDE) models the isothermal single-phase Darcian flow through porous media considering the variation in the properties of the rock and the fluid present inside its pores. Typically, the dimensionless solution of the linear hydraulic diffusivity equation (LHDE) pD⁢(rD,tD) for constant permeability oil flow in porous media is computed through Laplace and Fourier transform or Boltzmann transformation. For these cases, the dimensionless general solution in cylindrical coordinates is expressed by the transcendental function exponential integral Ei(rD,tD). This work develops analytically a new coupled perturbative-integro-differential model to solve the NHDE for oil flow in a permeability-pressure-sensitive reservoir with source. The general solution is computed combining a first-order asymptotic series expansion, Green’s functions (GF), and a Volterra’s second kind integro-differential formulation. A set of pore pressure and permeability values for two sandstones samples in an offshore reservoir from Brazil is obtained experimentally using the geomechanical elastic parameters (e.g., the Young’s modulus and Poisson’s ratio in addition to a uniaxial cell). These data are used as input in the computational code to run the analytical model and evaluate the reservoir permeability change. After these data input, the model runs and it allows to compute the instantaneous reservoir permeability values over the well-reservoir life cycle. The model calibration is performed by comparing the developed solution with a numerical porous media oil flow simulator named IMEX®, widely used in reservoir engineering and well-testing field operations and scientific works. The general solution of the NHDE mD(rD,tD) is computed by the sum of the linear solution pD(rD,tD) (constant permeability) and the first-order term of the asymptotic series expansion mD(1)(rD,tD), composed of the nonlinearity present in solution caused by the reservoir permeability variation. The results have shown that the developed solution is accurate, when compared to the numerical simulator, providing to be an attractive mathematical tool to help the well-reservoir management due to its low computational costs, when compared to the numerical simulators acquisition costs.

Numerical Evaluation of a Novel Slot-Drill Enhanced Oil Recovery Technology for Tight Rocks

Summary Enhanced oil recovery (EOR) is essential in shale/tight formations because primary recovery typically produces less than 10% of the original hydrocarbon in place. This work presents a novel “slot-drill” EOR (SDEOR) technology, which involves injecting gas through a horizontal fracture that is cut into the formation near the top of the reservoir (using a tensioned abrasive cable mounted to the drillstring) and producing oil from a second slot-drilled horizontal fracture near the bottom of the reservoir. A robust 3D projection-based embedded discrete fracture model (pEDFM; EDFM) is used to model the natural fractures in these slot-drilled unconventional oil reservoirs accurately and efficiently. Connectivity and uncertainty analyses are performed to determine the percolation threshold, where natural fractures influence hydrocarbon production appreciably. The results of this work indicate that the proposed technology can yield over a threefold increase in oil recovery relative to the cyclic gas EOR (CGEOR) method. This simulated recovery is high regardless of the presence of natural fractures or the type of gas/solvent injected (such as CH4, N2, CO2, and flue gas). The simulation results also indicate that the continuous gas injection, higher relative oil permeability, and the role of gravity-drainage are the main reasons why the oil recovery from the SDEOR is three times that from the CGEOR method. In conclusion, this is the first presentation and numerical simulation study of applying pairs of parallel slot-drilled fractures to enhance the recovery from challenging unconventional reservoirs (such as the Bakken shale) that have not been successfully enhanced using the CGEOR method. The dramatic increase in recovery from SDEOR, coupled with its applicability regardless of the stress state or formation brittleness, could change how unconventional reservoirs are completed and produced in the future.

A Fractal Permeability Model of Tight Oil Reservoirs Considering the Effects of Multiple Factors

The prediction of permeability and the evaluation of tight oil reservoirs are very important to extract tight oil resources. Tight oil reservoirs contain enormous micro/nanopores, in which the fluid flow exhibits micro/nanoscale flow and has a slip length. Furthermore, the porous size distribution (PSD), stress sensitivity, irreducible water, and pore wall effect must also be taken into consideration when conducting the prediction and evaluation of tight oil permeability. Currently, few studies on the permeability model of tight oil reservoirs have simultaneously taken the above factors into consideration, resulting in low reliability of the published models. To fill this gap, a fractal permeability model of tight oil reservoirs based on fractal geometry theory, the Hagen–Poiseuille equation (H–P equation), and Darcy’s formula is proposed. Many factors, including the slip length, PSD, stress sensitivity, irreducible water, and pore wall effect, were coupled into the proposed model, which was verified through comparison with published experiments and models, and a sensitivity analysis is presented. From the work, it can be concluded that a decrease in the porous fractal dimension indicates an increase in the number of small pores, thus decreasing the permeability. Similarly, a large tortuous fractal dimension represents a complex flow channel, which results in a decrease in permeability. A decrease in irreducible water or an increase in slip length results in an increase in flow space, which increases permeability. The permeability decreases with an increase in effective stress; moreover, when the mechanical properties of rock (elastic modulus and Poisson’s ratio) increase, the decreasing rate of permeability with effective stress is reduced.

Constructing Environmental-Friendly "Oil-Diode" Janus Membrane for Oil/Water Separation.

Oil leakage is a global environmental issue and happens frequently, resulting in a waste of oil resources and even threatening the safety of marine creatures and humans. Because of unidirectional oil transportation performance, "oil-diode" Janus membranes have attracted lots of attention for oil/water separation. However, the hydrophobic side of traditional "oil-diode" Janus membrane is completely hydrophobic, resulting in an easy permeation of oil, which hampers light oil recycling. Herein, we provide a facile approach to develop "oil-diode" Janus membranes with the special wettable structure for fast oil refining. The material characteristics and surface wettability of the membranes that generate superimposed efforts are vital to fabricate "oil-diode" Janus membranes. Interestingly, the manufactured membranes exhibit extra-high oil intrusion pressure up to 12 kPa and present high permeance of about 2993 L m-2 h-1 bar-1 in separating stable water-in-oil emulsion containing surfactant and separation efficiency up to 99.6%, thereby showing promising potential in oil recovery and refining.