Effect Of Interfacial Tension Research Articles

The pore-network modeling of gas-condensate flow: Elucidating the effect of pore morphology, wettability, interfacial tension, and flow rate

The gas-condensate flow in the near-well region is significantly influenced by phase behavior, flow regimes, and pore geometries. In conventional gas-condensate reservoirs the key pore-scale parameters affecting gas and condensate relative permeabilities include velocity (i.e., pressure gradient), interfacial tension (IFT), wettability, and pore structure. To examine the impact of these parameters, three-dimensional (3D) and two-dimensional (2D) pore-network models (PNMs) were developed. A proposed compositional model was used to implement the cyclic process of condensate corner flow (film flow for circular tubes) and condensate blockage. Response surface methodology (RSM) was employed to achieve high accuracy in phase equilibrium calculations and to enhance computational speed.The 3D PNM simulations of gas-condensate core-flood experiments confirmed the consistency and accuracy of the implemented methodology. A parametric study of governing factors such as pore shapes, wettability, IFT, and flow rate was conducted using the developed PNMs. The findings revealed that pore geometry and contact angle dictate the condensate meniscus curvature and snap-off process in pore throats. The unblocking of throats by condensate bridges was primarily controlled by contact angle, IFT, and pore cross-section. A shift to neutral wetting substantially improved gas-condensate flow in higher IFTs and angular pore shapes.The positive velocity effect on low-IFT gas-condensate flow, known as the coupling rate effect, was more pronounced in simulations with lower contact angles, and its impact was negligible at neutral wettability, similar to the IFT effect. The simulation results and findings underscore the influence of each factor and offer a method for incorporating the effects of pore shape (i.e., formation type and structure), contact angle, velocity, and IFT in continuum scale simulations.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Two-dimensional numerical modelling of viscous emulsion drops coalescence in a constricted capillary channel

We study numerically the coalescence of viscous emulsion drops in a two-dimensional semi-elliptical shape constricted channel. The Navier-Stokes equations are solved using the finite element method and the oil-water interface is tracked using the level-set techniques. Effects of interfacial tension, inertia, viscosity ratio, droplet size, and constriction shape on the droplet coalescence and average viscous pressure drop along the channel are investigated. It is found that at high interfacial tension, droplets are circular, approach each other more quickly, coalesce at the constriction entrance, and give higher pressure drops. At intermediate interfacial tension, the onset of coalescence occurs downstream of the constriction entrance while at very low interfacial tension, no coalescence of the droplets was observed. Inertia is found to be negligible effects on the coalescence of the droplets. High inertia gives less viscous pressure drop. Less viscous droplets are more likely to quickly coalesce compared to high viscous drops. Higher viscous drops create more resistance to flow. Moreover, larger size drops are responsible for more quick coalescence and tend to create more viscous pressure drops. In addition, we found that circular constriction offers less resistance to fluid flow. We hope that these numerical results would be beneficial while displacing oil from the underground reservoirs.

Hydrodynamic simulation of metal droplet settlement in molten slag

A mathematical model of the metal droplet settlement process of smelting slag was established. The effect of interfacial tension between the metal and slag phases on the droplet settlement velocity and drag force under different viscosity models was studied. The results showed that the Laminar and RNG k–ɛ turbulence models accurately predict the final settlement velocity of smaller diameter droplets. The interfacial tension affects the settlement velocity of the droplet, and the effect gradually increases as the droplet size is increased. The “RNG + CSS” model accurately describes the droplet settlement process and the change in the droplet settlement velocity. The drag force coefficient formula under coupling interfacial tension was derived with the established mathematical model and experimental data. This model reveals the mechanism of the settlement process of metal droplets in smelting slag and provides theoretical guidance for reducing the content of valuable metals in slag in actual production.

Effects of temperature and nanofluid type on the oil recovery from a vertical porous media in antigravity fluid injection

Recent researches indicate that the injection of nanofluid solutions into oil reservoirs enhances oil recovery, but the impact of key important parameters such as antigravity fluid injection has not yet been well understood. In current experimental investigation, effects of temperature and antigravity injection on the enhancement of oil recovery was studied. Additionally, effects of wettability alteration, interfacial tension, and viscosity were investigated. Pure water, TiO2, CuO, and γ-Al2O3 nanofluids were considered as injected fluid. During the antigravity fluid injection process, decreasing the capillary number enhanced the oil recovery. This increment for pure water, TiO2, CuO, and γ-Al2O3 nanofluids injection was 42.8%, 65.7%, 73.5%, and 75.7%, respectively. Compared to the gravity-aligned injection, these results show enhancement by up to 18.25%, 19.7%, 17.5%, and 23.7%. Moreover, for injection in antigravity direction when water, TiO2, CuO, and γ-Al2O3 nanofluids injected at 90 °C oil recovery enhanced by 7.8%, 5.2%, 3.7%, and 2.75%, respectively, compared to the results obtained for injection at 25 °C. Besides, oil recovery enhanced substantially by interfacial tension reduction when using nanofluids instead of water. For instance, the maximum recovery belongs to γ-Al2O3 nanofluid by 43.5% as the interfacial tension reduced from 45.03 mN/m for oil-water to 2.36 mN/m for oil and γ-Al2O3 nanofluid. Furthermore, increasing the injection temperature from 25 °C to 90 °C reduced the interfacial tension. This reduction for water injection was 15.8%, and 21.2% for γ-Al2O3 nanofluid injection.

Investigation on Imbibition Mechanism of Tight Core Based on NMR Test.

Seepage is important to improve the postpressure production enhancement effect of tight oil and gas reservoirs. To study the microscopic percolation law of different pores, this paper first characterizes the pore structure of tight cores. High-pressure spontaneous percolation experiments and nuclear magnetic resonance (NMR) tests were combined. The T 2 spectra at different times of percolation were used. The percolation law of different pore types was quantitatively characterized from a microscopic perspective. The effect of different interfacial tensions on the percolation was clarified. Results show that the pore size has a good match with the NMR T 2 relaxation time. The core pore development is dominated by submicrometer pores, which account for more than 70%. The percolation rate is fast at the beginning and then decreases and stabilizes at 48 h. The pore size of the submicropore is small, the capillary force is large, and the recovery rate of percolation is high, followed by those of the micropore and the medium-pore. The higher the porosity and permeability of the core, the greater the overall seepage recovery rate. The sensitivity of submicrometer pores to interfacial tension is great, and the recovery rate increases by 40.9% when the interfacial tension decreases from 17.1 to 1.46 mN/m. Furthermore, as the interfacial tension decreases, the recovery rate of different pores appears to increase first and then decrease. The surfactant formulation must be selected reasonably in practical production.

Modeling Two-Phase Flow in Tight Core Plugs with an Application for Relative Permeability Measurement

Summary The two-phase flow of immiscible fluids in porous media has been studied for a long time in different disciplines of engineering. Relative permeability (kr) is one of the constitutional relationships in the general equation governing immiscible displacement that needs to be determined. Due to the complexity and nonlinear nature of governing equations of the problem, there is no unique model for relative permeability. The modified Brooks and Corey (MBC) model is the most common model for kr prediction. Here, a practical technique is presented to measure kr for low-permeability tight rocks. We use this experimental data to tune the empirical constants of the MBC model. The proposed method is based on a simple mathematical technique that uses assumptions of frontal advance theory to model the pressure drop along the core plug during two-phase immiscible displacement at constant injection flow rate. We make simplifying assumptions about the highest point on the observed pressure profile and use those assumptions to determine relative permeability of a tight rock sample. In the end, the amount of work for an immiscible displacement is calculated as the area under the pressure-profile curve. The effect of initial water saturation (Swi) and interfacial tension (IFT) is studied on the work required for an immiscible displacement. Using this concept, it is concluded that adding chemical additives such as surfactants to fracturing fluids can help the reservoir oil to remove the water blockage out of the rock matrix more easily while maintaining the flow rate at an economic level.

Effect of Polar Hydrocarbon Contents on Oil-Water Interfacial Tension and Implications for Recent Observations in Smart Water Flooding Oil Recovery Schemes.

For decades now, low salinity water flooding (LSWF) oil recovery has emerged as an environmentally benign and cost-effective method for improved oil recovery, where research findings have reported pH and interfacial tension effects. Considering the effect of oil chemistry on interfacial tension and the potential of this chemistry to have a direct relationship with LSWF, we measured the interfacial tension of four crude oils with composition varying from those of conventional to unconventional ones. We also characterized the crude oil samples using infrared spectroscopy and a wet chemistry method based on asphaltene precipitation. Our research approach has enabled us to relate the composition of crude oil to the interfacial tension trend at pH encountered in improved oil recovery schemes. Our research methodology, based on an integrated approach to using infrared spectroscopy and interfacial tensiometry, has also enabled us to propose a more robust theoretical explanation for current observations in LSWF related to pH and interfacial tension. In this regard, oil-water interfacial tension depends on the concentration of polar components, such that the higher the concentration of polar groups in crude oil, the higher the interfacial tension at a given pH of aqueous solution. We have also shown that the acid-base behavior of polar groups at the oil-water interface provides a theoretical interpretation of the explicit relationship between oil-water interfacial tension and the electrostatic components of interfacial tension as given by the energy additivity theory.

The effect of interfacial tension on CO2 oil-based foam stability under different temperatures and pressures

Gas channeling easily occurs in CO2 flooding, leading to lower oil production efficiency. CO2 oil-based foam can effectively control gas channeling, so it is particularly important to study the stability of CO2 oil-based foam to improve oil recovery. In this paper, an oil-based foam system was constructed by evaluating many different surfactants, and then the viscosity of the base oil and the type of gas were changed to study their influence on the stability of the oil-based foam. The stability of CO2 oil-based foam under high temperature and high pressure was analyzed. Finally, the influence of CO2-oil interfacial tension (IFT) on the stability of oil-based foam was investigated. The results show that the CO2 oil-based foam system composed of compound foaming agent FS with a total concentration of 2 wt% and a ratio of FCO-80 to Span 20 of 3:7 and an oil phase with a viscosity of 2.98 mPa·s have excellent foaming performance. In Zones I and II, the CO2-oil IFT is too low, a miscible or near miscible system is formed, and the system cannot generate foam. Although the IFT in Zone III is low, the film’s strength is low, which leads to no foam in the system. The temperature and pressure conditions in zone IV are suitable for an oil-based foam system to generate foam. Under the same foam system, there is a critical CO2-oil IFT at different temperatures, which can be used as a standard to criterion whether the system can foam. This paper has meaningful guiding significance for improving the stability mechanism of CO2 oil-based foam under different temperatures and pressures and controlling gas channeling in the process of CO2 flooding.

Laminar drag reduction ability of liquid-infused microchannels by considering different infused lubricants.

We numerically investigate the pressure drop reduction (PDR) performance of microchannels equipped with liquid-infused surfaces, along with determining the shape of the interface between the working fluid and lubricant within the microgrooves. The effects of different parameters, such as the Reynolds number of working fluid, density and viscosity ratios between the lubricant and working fluid, the ratio of the thickness of the lubricant layer over the ridges to the depth of the groove, and the Ohnesorge number as a representative of the interfacial tension, on the PDR and interfacial meniscus within the microgrooves are comprehensively studied. The results reveal that the density ratio and Ohnesorge number do not significantly affect the PDR. On the other hand, the viscosity ratio considerably affects the PDR, and a maximum PDR of 62% compared to a smooth non-lubricated microchannel is achieved for a viscosity ratio of 0.01. Interestingly, the higher the Reynolds number of the working fluid, the higher the PDR. The meniscus shape within the microgrooves is strongly affected by the Reynolds number of the working fluid. Despite the insignificant effect of interfacial tension on the PDR, the interface shape within the microgrooves is appreciably influenced by this parameter.

Computational simulation of the effects of interfacial tension in microfluidic flow focusing droplet generators

We present simulations of a square flow focusing droplet generator device exploring its performance characteristics over a range of interfacial surface tension values and varying neck width. Droplet generators have a wide range of applications from drug delivery to X-ray diffraction experiments. Matching the droplet frequency and volume to the experimental parameters is critical for maximising the data quality and minimising sample waste. Whilst varying the interfacial surface tension we observed that the lowest frequency of droplets is generated for surface tensions matching those typically reported for water-oil mixtures (around 40 mN/M). Decreasing or increasing the interfacial surface tension, for example by adding surfactant, results in an increase in droplet frequency. We also find that under the conditions simulated here, droplets are generated with much lower capillary numbers and higher Weber numbers than have typically been reported in the literature. The high ratio of flowrate-to-cross-section used here resulted in a velocity which was larger than has previously been reported for flow focusing devices and consequently we observe particularly large associated Reynolds numbers. However, in general, the simulated flow behaviour characteristics most closely match those typically observed for the jetting and tip-streaming regimes. The highest frequency of droplets achieved in our simulated devices was 36 kHz and 56 kHz corresponding to square neck channel widths of 12.5 and 25 µm respectively, an interfacial surface tension of 118.75 mN/m. We also examined the effect of varying neck width geometry for a fixed interfacial surface tension of 52 mN/m. We observed that the highest frequency droplet generation, 61 kHz, corresponded to a neck width of 37.5 µm with a corresponding droplet diameter of 22 µm. The high frequency, high monodispersity, and small droplet size predicted to occur through modification of the interfacial surface tension will have implications for the future design and optimisation of droplet-on-demand microfluidic devices.

A pressure approach of cumulant phase-field lattice Boltzmann method for simulating multiphase flows

The cumulant lattice Boltzmann method (LBM) has been recently used to simulate multiphase-multicomponent flows by applying an external force. Furthermore, the mass and momentum are not conserved when an external force is used. In the classical approach, the third-order derivatives in density necessitate information from a large stencil of neighbors, which affects parallelization and is computationally expensive. In this paper, we propose an equilibrium distribution function in the moment space, which includes diagonal and off diagonal elements of the pressure tensor. Consequently, the interfacial tension effect can be exerted into this equilibrium function, circumventing the need for an external force. The Cahn–Hilliard equation can be coupled to the method to track the interface at multiphase-multicomponent flows. This function is applied on the moment, central, and cumulant LBM and transferred back to the discrete space to be used in Bhatnagar–Gross–Krook LBM. These key advantages include simplicity, easy-to-implement, and high parallelization capability due to removing high-order derivatives. An immiscible two-component flow between two parallel plates is simulated and compared with the analytical solution at different viscosities for the moment LBM and the cumulant LBM. Numerical results are in good agreement with analytical solutions. Moreover, a dispersed droplet in a continuous phase under shear flow is simulated to show the capability of the proposed method in the breaking-up process modeling. It is demonstrated that spurious velocities are less affected by decreasing the viscosity and cumulant LBM with the proposed function, while the interfacial tension is calculated accurately. Finally, the method has been extended for three dimensions, and two cases of a three-dimensional breakup of a liquid thread and collision of two equal droplets are studied to show the ability of this method to simulate the coalescence and breakup process.

Modeling of Interfacial Tension and Inclusion Motion Behavior in Steelmaking Continuous Casting Mold.

The current work is an expansion of our previous numerical model in which we investigated the motion behavior of mold inclusions in the presence of interfacial tension effects. In this paper, we used computational fluid dynamic simulations to examine the influence of interfacial tension on inclusion motion behavior near to the solid-liquid interface (solidifying shell). We have used a multiphase model in which molten steel (SPFH590), sulfur, and alumina inclusions have been considered as different phases. In addition, we assume minimal to negligible velocity at the solid-liquid interface, and we restrict the numerical simulation to only include critical phenomena like heat transport and interfacial tension distribution in two-dimensional space. The two-phase simulation of molten steel mixed with sulfur and alumina was modeled on volume of fluid (VOF) method. Furthermore, the concentration of the surfactant (sulfur) in molten steel was defined using a species model. The surfactant concentration and temperature affect the Marangoni forces, and subsequently affects the interfacial tension applied on inclusion particles. It was found that the alteration in interfacial tension causes the inclusion particles to be pushed and swallowed near the solidifying boundaries. In addition, we have compared the computational results of interfacial tension, and it was found to be in good agreement with experimental correlations.

Assessing the apparent viscosity of decane-water emulsion in underground porous media based on the lattice Boltzmann method

The groundwater system is one of the most important subsurface resources on Earth, which offers many important services to humankind, such as irrigated agriculture, household use, and manufacturing. However, the safety of groundwater resources is seriously threatened by contamination from human activities. The emulsion has been proposed as a potential solution for the removal of contaminants due to its high apparent viscosity. Here we reveal the pore-scale mechanism for the viscosity increase in decane-water emulsions by lattice Boltzmann simulations. We assess the effect of phase saturation, interfacial tension, and contact angle, on the apparent viscosity of decane-water emulsions in porous media. Our results show that the apparent viscosity of the emulsion reaches its maximum value when the decane saturation is around 20%. We also find that this maximum viscosity increases with interfacial tension, and it is larger in decane-wet or water-wet systems than it is in intermedia-wet media.

Determination of Fuel Saturated Dissolved Water Content and Its Influencing Factors

The presence of undissolved water in fuel can significantly impact the safety, stability, and durability of engine operation. Karl Fischer titration is a cost-effective and convenient approach to accurately measure the total water content in the fuel. The undissolved water content can be determined by subtracting the saturated dissolved water content from the total water content. This paper outlines a methodology for preparing dissolved water saturated fuel and investigates the effect of temperature and interfacial tension on the saturation solubility of water in 0# diesel fuel and 3# jet fuel. The results show that the saturated dissolved water content of the two fuels is linearly and positively correlated with the temperature; the use of surfactants was shown to decrease interfacial tension, thereby promoting the combination of fuel and water molecules and increasing saturated water solubility; molecular surfactants were more effective at combining fuel and water molecules than ionic surfactants when interfacial tension was held constant.

Pore-scale Analysis of CO2-brine Displacement in Berea Sandstone and Its Implications to CO2 Injectivity

For storage in deep saline formations, where CO2 is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO2 injectivity is considered to reach the maximum value at the CO2 endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO2-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO2-brine flow in the sample of Berea sandstone. CO2/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO2 storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO2 displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO2 injectivity. The result shows that water-wet condition facilitates the CO2 injection when there is no fracture induced.

Anisotropic pressure effects on nanoconfined water within narrow graphene slit pores.

There is an increasing interest toward disclosing and explaining confinement effects on liquids, such as water or aqueous solutions, in slit pore setups. Particularly puzzling are the changes of physical and chemical properties in the nanoconfinement regime where no bulk-like water phase exists between the two interfacial water layers such that the density profile across the slit pore becomes highly stratified, ultimately leading to bilayer and monolayer water. These changes must be quantified with respect to some meaningful reference state of water, the most natural one being bulk water at the same pressure and temperature conditions. However, bulk water is a homogeneous liquid with isotropic properties, whereas water confined in slit pores is inhomogeneous, implying anisotropic properties as described by the perpendicular and parallel components of the respective tensors. In the case of pressure, the inhomogeneous nature of the setup results in a well-defined difference between the perpendicular and parallel pressure tensor components that is uniquely determined by the interfacial tension being a thermodynamic property. For bilayer water constrained in graphene slit pores that are only about 1 nm wide, we demonstrate that there exists a thermodynamic point where the pressure tensor of the inhomogeneous fluid, nanoconfined water, is effectively isotopic and the pressure is thus scalar as in the homogeneous fluid, bulk water. This specific point of vanishing effective interfacial tension is proposed to serve as a well-defined reference state to compare the properties of nanoconfined liquids to those of the corresponding bulk liquid at the same (isotropic) pressure and temperature conditions. In future work, this idea could be applied to assess confinement effects on chemical reactivity in aqueous solutions as well as to other nanoconfined liquids in other pores such as layered minerals.

Pore-Scale Numerical Simulation of CO2–Oil Two-Phase Flow: A Multiple-Parameter Analysis Based on Phase-Field Method

A deep understanding of the pore-scale fluid flow mechanism during the CO2 flooding process is essential to enhanced oil recovery (EOR) and subsurface CO2 sequestration. Two-phase flow simulations were performed to simulate the CO2 flooding process based on the phase-field method in this study. Two-dimensional models with random positions and sizes of grains of circular shape were constructed to reproduce the topology of porous media with heterogeneous pore size distributions in the reservoir rock. A multiple-parameter analysis was performed to investigate the effects of capillary number, viscosity ratio, wettability, density, gravity, interfacial tension, and absolute permeability on the two-phase fluid flow characteristics. The results indicated that when the capillary number and viscosity ratio were large enough, i.e., log Ca = −3.62 and log M = −1.00, the fingering phenomenon was not obvious, which could be regarded as a stable displacement process. CO2 saturation increased with the increase in the PV value of the injected CO2. Once the injected CO2 broke through at the outlet, the oil recovery efficiency approached stability. Two types of broken behaviors of the fluids were observed during the wettability alternation, i.e., snap-off and viscous breakup. Snap-off occurred when capillary forces dominated the fluid flow process, while viscous breakup occurred with a low viscosity ratio. With a low capillary number, the flooding process of the injected CO2 was mainly controlled by the capillary force and gravity. With the decrease in the interfacial tension between the fluids and the increase in the permeability of the porous media, the recovery of the displaced phase could be enhanced effectively. In the mixed-wet model, with the increase in the percentage of the nonoil-wetted grains, the intersecting point of the relative permeability curve moved to the right and led to a higher oil recovery.

Hydrodynamic characteristics of liquid–liquid–liquid three-phase flow in a confined microchannel

Numerical simulations have been performed to reveal the hydrodynamic characteristics of liquid–liquid–liquid three-phase flow in a confined microchannel via a VOF-CSF model. Further the effects of outer phase flowrate, dimensions, the viscosities of all three phases as well as the interfacial tensions of both inner and outer interfaces are systematically investigated. It is found that the shear stress and pressure gradient together determine the formation and disappearance of vortices inside the compound droplets. The internal fluid velocity of compound droplets is significantly altered by the flowrate and viscosity, while the effect of interfacial tension can be ignored. As for the vorticity distribution inside the compound droplets, it exhibits a positive correlation with the capillary number of outer phase. Besides, a prediction correlation for the average velocity of compound droplets with several dimensionless numbers is also established with good precision. The results obtained in this study could provide meaningful theoretical guidance for rational design and regulation of transport behaviors with liquid–liquid–liquid three-phase flow in a confined microchannel.

Experimental study of oil recovery mechanisms during imbibition in tight sandstone with different fluid displacing agents under ambient and reservoir pressure

This study explores oil recovery mechanisms of static imbibition in a tight sandstone under different imbibition pressures, simultaneously optimizing imbibition agents. To this end, the static imbibition experiments of two common agents, polyacrylamide (PAM) slick water and anion–nonionic surfactants, are conducted under atmospheric and reservoir pressure (20 MPa). The interfacial tension and contact angle of these two imbibition fluids are also measured. Herein, the entire recovery period and imbibition equilibrium time vs. pressure are determined. Based on NMR and high-pressure mercury injection measurements, the contributions of pores with different sizes to the displacement recovery during imbibition are quantified. Under atmospheric pressure, the recovery rate with the surfactant was measured higher than that of the PAM slick water. The main reason was that the former has a lower interfacial tension (0.0961 mN/m), stronger hydrophilicity (average contact angle 27.7°), and stronger oil-displacing effect. Under a reservoir pressure of 20 MPa, the surfactant had lower recovery rate than the PAM slick water, while the latter enhanced the recovery further. Under atmospheric pressure, both agents recovered the crude oil in the medium-sized and larger pores whereas, under reservoir pressure (20 MPa), they mainly recovered oil from the smaller and medium-sized pores. At higher imbibition pressures, both agents recovered more oil from the smaller and medium-sized pores, and less from micropores and larger pores. This indicated that higher pressures can further improve the driving force of fluid replacement, to improve oil production from finer and medium-sized pores significantly. Under atmospheric pressure, both agents reached imbibition equilibrium in approximately 20 days while this period was reduced for the surfactant and slick water to 16 and 12 days, respectively. Based on the results PAM slick water is recommended for EOR purposes in tight sandstone which can be generalized to similar formations around the globe.