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The properties of foam fluid are substantially determined by its interfacial dynamics changes during foam transport. In this research, a foam flow simulation model based on the level set method and the N–S equation with surface tension term is established to simulate the dynamic interface evolution mechanism of group foam and individual foam from various aspects such as drainage process and foam migration in porous media, coalescence and Jamin effect. The results show that the foam life decreases linearly with the logarithm of the surface tension and enhances linearly with the liquid viscosity. For foam transport in porous media, both flowing foam and trapped foam exist, and the pressure fluctuates at a certain pressure value and the best foam structure is achieved at the optimum conditions with the optimum values of gas-liquid ratio, surface tension, and porosity being 1:1˜3:2, 0.1˜0.3, and 44.4%, respectively. Besides, the temporary blocking effect of foam has been verified. During the foam coalescence, foam gradually evolves towards minimum interfacial energy with oscillating and gradually decreasing foam volume. During the process of the foam passing through the throat, the maximum pressure occurs when the front end of the foam reaches the narrowest point, and the minimum pressure occurs when half of the foam passes through the narrowest point. The maximum pressure elevates linearly with the surface tension and the inverse of the throat radius. [ABSTRACT FROM AUTHOR]

Stochastic Bubble Population (SBP) balance model has been widely applied on investigation of surfactant foam flow characteristics in porous media, while its application on predict nanoparticle (NP)-stabilized foam behavior has not been well refined. There are two empirical parameters in the SBP model, namely, the bubble generation rate K g and the maximum bubble density n max. To qualify the SBP model on prediction of the transient NP-stabilized foam propagation behavior, we make the efforts to calibrate the parameters of K g and n max based on the literature reported systematic experimental results. Through five sets of simulations in correspondence to the experimental works, it is found K g has little effect on the pressure drop along the core, while the n max increases from 200 mm−3 to 8000 mm−3 with the addition of NPs and the increment of NP concentration. Larger n max values at higher NP concentrations indicates the foam stabilized by NPs has stronger foam structure and therefore leads to a better displacement result. It is concluded that based on the simple but carefully calibrated parameters, SBP model could provide accurate predictions of NP-stabilized foam flow characteristic in porous media. [ABSTRACT FROM AUTHOR]

Understanding the fracture effect on the two-phase displacement process in porous media is potential for fulfilling the efficient development of geo-energy resources. In this paper, a pore-scale numerical study is carried out based on digital rock physics (DRP) and computational fluid dynamics (CFD) methodology. Advanced image processing technology is employed to incorporate the fracture structure of different aperture sizes in the rock pore matrix, and the sophisticated CFD approach is employed to simulate the single-phase and two-phase displacement flow characteristics in fractured porous media. In single flow cases, it is found that larger fractures always lead to higher water flow rates, therefore resulting in higher rock permeability. For the specific water flooding oil two-phase flow process under a pressure drop of 500 Pa, the presence of fractures could help achieve a steady flooding process that cannot be fulfilled in the homogeneous core due to the interfacial tension (IFT) blockage effect. Under a higher pressure drop of 1000 Pa, the relationship between the ultimate oil displacement rate and the aperture size is not uniform. The optimal oil recovery rate of 82.4% is achieved at the model with the intermediate aperture size. [Display omitted] [ABSTRACT FROM AUTHOR]

Foam technology has shown great potential in enhancing oil recovery as well as fulfilling carbon geological storage practices in mature and low permeability reservoirs. To reveal the mechanism of the foam quality effect on foam displacement behavior in underground formations, numerical studies on three-phase foam flow characteristics in porous media have been carried out based on the Stochastic Bubble Population Balance (SBPB) model. Through modifying the injection gas and liquid rate ratio, various foam qualities between 40% and 90% have been set, and the effect of foam quality was taken into account with higher foam quality corresponding to the larger maximum bubble density parameter in the SBPB model. Comprehensive numerical results, including the dynamic distribution curves of the oil, water, and foam phase saturation, oil phase pressure, and the foam bubble density along the flow direction, were obtained under different foam quality cases. Parameter investigations on the bubble generation rate and the oil viscosity were carried out as well. It is observed the pressure drop and water recovery rate of the foam flooding process increases monotonously with the increasing foam quality, while the ultimate oil recovery rate shows the highest value at the intermediate foam quality of 70%. The numerical results on the foam quality effect agree well with reported experimental observations, indicating the SBPB model could characterize in mechanism the three phase foam displacement behavior in porous media. [Display omitted] [ABSTRACT FROM AUTHOR]

Accurate and fast determination of the diffusion coefficient of the CO 2 /oil system is essential in CO 2 enhanced oil recovery (CO 2 -EOR) and CO 2 geological sequestration practices. In this work, a novel methodology is proposed and demonstrated on measuring the diffusion coefficient of the immiscible CO 2 /oil binary systems based on quantification of the oil droplet swelling behavior. Five oil samples, including n-decane, n-dodecane, n-tetradecane, n-hexadecane and liquid paraffin, are employed as the oil phase and the diffusion coefficient for each CO 2 /oil system were determined. After validation of the methodology based on good agreements between the measurement and the reported results for both the pure component oil and the synthetic oil, the diffusion characteristics of the CO 2 /oil systems are scrutinized in the pressure range 2–10 MPa and the temperature range 26.9–82.1 ℃. The measurement results clearly show the elevated system pressure could lead to stronger diffusion processes between the CO 2 and the oil phase, while the temperature impacts on the diffusion process are more complex due to the synergistic effects of CO 2 density and the oil viscosity. Performed in the state-of-the-art drop shape analyzer within a short measurement period, it is expected the proposed methodology could provide an efficient supplementary for diffusion coefficient measurements of the CO 2 /oil binary systems. [Display omitted] [ABSTRACT FROM AUTHOR]

Accurate and fast determination of the diffusion coefficient of the CO 2 /oil system is essential in CO 2 enhanced oil recovery (CO 2 -EOR) and CO 2 geological sequestration practices. In this work, a novel methodology is proposed and demonstrated on measuring the diffusion coefficient of the immiscible CO 2 /oil binary systems based on quantification of the oil droplet swelling behavior. Five oil samples, including n-decane, n-dodecane, n-tetradecane, n-hexadecane and liquid paraffin, are employed as the oil phase and the diffusion coefficient for each CO 2 /oil system were determined. After validation of the methodology based on good agreements between the measurement and the reported results for both the pure component oil and the synthetic oil, the diffusion characteristics of the CO 2 /oil systems are scrutinized in the pressure range 2–10 MPa and the temperature range 26.9–82.1 ℃. The measurement results clearly show the elevated system pressure could lead to stronger diffusion processes between the CO 2 and the oil phase, while the temperature impacts on the diffusion process are more complex due to the synergistic effects of CO 2 density and the oil viscosity. Performed in the state-of-the-art drop shape analyzer within a short measurement period, it is expected the proposed methodology could provide an efficient supplementary for diffusion coefficient measurements of the CO 2 /oil binary systems. [Display omitted] [ABSTRACT FROM AUTHOR]

CO 2 miscible flooding is one of the most ideal scenarios in oil recovery practices. Accurate prediction of the minimum miscible pressure (MMP) of the CO 2 /oil system is essential for CO 2 Enhanced Oil Recovery (CO 2 -EOR) and carbon geological storage applications. In this paper, a novel method based on quantification of the oil droplet volume shrinkage behavior is proposed and demonstrated in the determination of the MMP of the CO 2 /n-hexadecane (n-C 16 H 34) system and the CO 2 /n-octadecane (n-C 18 H 38) system. Based on the specific quantitative criterion of the oil droplet volume reduction rate, the MMPs of the CO 2 /oil system under different temperature levels were determined. The accuracy of the measurement results has been validated with the corresponding thermodynamic phase equilibrium calculation results. To show the application potential of the proposed method, detailed discussions have been provided based on comparisons with the Vanishing Interfacial Tension (VIT) method. It is expected the proposed Oil Droplet Volume Measurement (ODVM) method could act as a robust supplementary for studying the miscibility characteristics of the CO 2 /oil system. [Display omitted] • A novel Oil Droplet Volume Measurement (ODVM) method is proposed to measure the MMPs of the CO 2 /medium oil system. • The measurement results are validated with the thermodynamic calculations. • Comparisons with the Vanishing Interfacial Tension (VIT) method are reported. [ABSTRACT FROM AUTHOR]

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. [Display omitted] [ABSTRACT FROM AUTHOR]

Determination of the diffusion coefficient of a miscible Supercritical CO 2 (ScCO 2) and oil system is substantial for guiding the CO 2 EOR and greenhouse gas geological storage practices. Based on the oil droplet interface shrinkage behavoir after reaching miscibility with the surrounding CO 2 , the diffusion coefficients of a miscible ScCO 2 /paraffin system were measured with the Dynamic Pendant Drop Volume Analysis (DPDVA) technique. A refined diffusion coefficient derivation model was proposed and validated for the CO 2 /oil system at the Minimum Miscibility Pressure (MMP) points. The measurements were performed under pressure range of 9–21 MPa and temperature range of 40.6–81.2 ℃. Exponential relationships have been obtaind between the diffusion coefficient and the pressure and the intrinsic oil viscosity, revealing the fact that the diffusion rate increases significantly with the system pressure after reaching miscibility. On the other hand, it is found higher temperature could retard the diffusion process between the ScCO 2 and the oil phases under miscible conditions. [Display omitted] • A refined diffusion coefficient derivation model is proposed for the miscible CO 2 /oil system. • The diffusion characteristics of the ScCO 2 /liquid paraffin system under miscibility conditions are successfully measured. • The relationships between the diffusion coefficient and the pressure as well as temperature are clearly revealed. [ABSTRACT FROM AUTHOR]

In correspondence to the bright prospects of CO2 EOR technology on greenhouse gas geological storage as well as oil recovery enhancement practices, the phase equilibrium characteristics of CO2/oil/water system was investigated in this paper. n-Hexadecane (n-C16H34) is employed as the oil component and water is introduced into the two phase system as the dissolved component in CO2. PR-EOS with modified alpha functions and Binary Interaction Parameters (BIPs) is employed to calculate the Minimum Miscibility Pressure (MMPs) of the CO2/n-C16H34 system with or without water presence at three temperatures of 40.3 ℃, 55.4 ℃ and 70 ℃. Calculation model and the employed parameters were validated through comparison with corresponding measurements, including the observation on decreased MMPs of the CO 2 /H 2 O/n-C 16 H 34 system in comparison with the CO 2 /n-C 16 H 34 system. Parameter studies were carried out for the CO 2 /n-C 16 H 34 system with or without water presence at different molar ratios. It is found the existence of water component could reduce the MMP values of the CO 2 /n-C 16 H 34 system and the degree of the MMP reduction was related to the molar ratio of CO 2 in the system. Higher CO 2 molar ratio could result in larger MMP deviation between CO 2 /C 16 H 34 system and CO 2 /H 2 O/C 16 H 34 system. [Display omitted] [ABSTRACT FROM AUTHOR]