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To solve the problems of shear degradation and injection difficulties in conventional polymer flooding, the capsule polymer flooding for enhanced oil recovery (EOR) was proposed. The flow and oil displacement mechanisms of this technique were analyzed using multi-scale flow experiments and simulation technology. It is found that the capsule polymer flooding has the advantages of easy injection, shear resistance, controllable release in reservoir, and low adsorption retention, and it is highly capable of long-distance migration to enable viscosity increase in deep reservoirs. The higher degree of viscosity increase by capsule polymer, the stronger the ability to suppress viscous fingering, resulting in a more uniform polymer front and a larger swept range. The release performance of capsule polymer is mainly sensitive to temperature. Higher temperatures result in faster viscosity increase by capsule polymer solution. The salinity has little impact on the rate of viscosity increase. The capsule polymer flooding is suitable for high-water-cut reservoirs for which conventional polymer flooding techniques are less effective, offshore reservoirs by polymer flooding in largely spaced wells, and medium to low permeability reservoirs where conventional polymers cannot be injected efficiently. Capsule polymer flooding should be customized specifically, with the capsule particle size and release time to be determined depending on target reservoir conditions to achieve the best displacement effect. [ABSTRACT FROM AUTHOR]

In the chemical flooding process, the premature breakthrough of chemical agents in production wells results in a large waste of chemical agents and increases the volume and processing difficulty of the produced fluids. The early warning method of chemical agent channeling can predict the strength of agent channeling in advance. The practice of chemical flooding shows that the production performance can be used for early warning of chemical agent channeling. In this paper, we analyze the relationship between cumulative oil production and cumulative polymer production of production wells in polymer–surfactant flooding. Three types of curves according to the enhanced oil production characteristics of chemical flooding, including convex type, S‐type, and concave type. We use the drop speed of the water–oil ratio and the rapid‐decline speed of water cut as early warning indicators to predict the channeling coefficient. A Latin hypercube experimental design method is used to design a polymer–surfactant flooding scheme with the main control factors of the channeling coefficient and early warning indicators. Numerical simulation is used to calculate samples of the channeling coefficient and early warning indicators under various conditions. The drop speed of the water–oil ratio reference value model and the rapid‐decline speed of the water cut reference value model are determined with a multiple regression method. A prediction model for the chemical agent channeling coefficient is established using the deviation coefficient of an early warning index. The method is applied in the Ng54‐61 polymer–surfactant flooding pilot area in the west of the Gudong Seventh District, Shengli Oilfield, China, and the error between the predicted result and the actual value is less than 10%. This research is helpful in taking effective antichanneling measures and improving the oil recovery degree of chemical flooding reservoirs. [ABSTRACT FROM AUTHOR]

Crude oil in underground porous media can be emulsified by surfactants, which can lead to improved oil recovery. However, there have been limited investigations revealing the interactions between emulsions and grains and comparing the influence of different factors on the distribution of emulsions in porous media at the pore scale. In this study, a solution containing surfactant was injected into an oil-saturated microchip with heterogeneous pore geometries. A series of tests were conducted by varying the injection rate, surfactant concentration, oil viscosity, and displacing phase viscosity. Qualitative analysis of flow mechanisms and quantitative analysis of the distribution of emulsions were performed through pore-scale snapshots. The results demonstrate that emulsions undergo deformation, breakup, and retention in porous media. Furthermore, new micro-interactions between emulsion droplets and grains are discovered, including the impact effect, cutting effect, and the synergy of both effects. A high flow rate of the displacing phase promotes the formation of more and smaller emulsions, while a low flow rate encourages flow diversion. An increase in oil viscosity and a decrease in surfactant concentration are not conducive to the formation of emulsions. However, an increase in the displacing phase viscosity promotes the formation of emulsions and flow diversion. The experiments provide detailed insights into the flow behaviors of emulsions at pore scale and offer valuable information for surfactant flooding. [ABSTRACT FROM AUTHOR]

Heterogeneity plays a vital role in the micro-flow through porous media, but experimentally observing the flow details is time-consuming. This study provides a fast method for displacement front prediction in various heterogeneous porous media based on deep learning and orthogonal design. It uses the orthogonal design to generate displacement schemes with different permeability contrasts, capillary numbers, and viscosity ratios and utilizes the lattice Boltzmann simulation to obtain the datasets of displacement front at breakthrough. The prediction network is then established based on the U-Net structure. Finally, the displacement fronts of porous media with various heterogeneities are predicted. Compared to training with a dataset generated by random sampling, this method can halve the time required to establish the dataset and network training without compromising accuracy. Three orders of magnitude reduce the time necessary for network prediction compared to the lattice Boltzmann simulation. The results indicated that the total water saturation decreases as the permeability contrast increases and the water saturation and front position ratios rise. As the permeability contrast grows, the influence of the capillary number and viscosity ratio on the water saturation and front position ratios becomes more pronounced. And the influence of the viscosity ratio on total water saturation is more significant in low permeability contrast porous media. This research is helpful for the study of microscopic channeling and remaining oil distribution and further guides reservoir development. [ABSTRACT FROM AUTHOR]

This study aimed to elucidate the effect of bone marrow mesenchymal stem cell (BMSC) transplantation combined with the administration of Lugua polypeptide injection into the knee joint cavity to treat knee osteoarthritis (KOA) in rabbits. Sixty white New Zealand rabbits were randomly divided into the blank, model, Lugua polypeptide, BMSC, and combined (Lugua polypeptide plus BMSC) groups, with 12 rabbits in each group. The mRNA and protein expression levels of cyclin D1, bcl-2, TIMP-1, p21, caspase-3, Bax, MMP-1, MMP-13, TLR-4, and NF-κB p65 in chondrocytes, and levels of IL-1, NO, TNF-α, and IL-6 in the synovial fluid were compared. The severity of cartilage damage in the combined group was significantly less (P <0.01). Compared to the MG, the mRNA and protein expression levels of cyclin D1, bcl-2 and TIMP-1 in chondrocytes of the three other groups were significantly increased, while those of p21, caspase-3, Bax, MMP-1, MMP-13, TLR-4, and NF-κB p65 in the chondrocytes and levels of IL-1, NO, TNF-α, and IL-6 in the synovial fluid of the three other groups were significantly reduced (P <0.05). The aforementioned indicators in the combined group were significantly better than those of the Lugua polypeptide and BMSCs groups (P <0.05). BMSC transplantation combined with Lugua polypeptide injection may improve KOA-related cartilage tissue damage in rabbits. [ABSTRACT FROM AUTHOR]

Foam flooding is an effective method for enhancing oil recovery in high water-cut reservoirs and unconventional reservoirs. It is a dynamic process that includes foam generation and coalescence when foam flows through porous media. In this study, a foam flooding simulation model was established based on the population balance model. The stabilizing effect of the polymer and the coalescence characteristics when foam encounters oil were considered. The numerical simulation model was fitted and verified through a one-dimensional displacement experiment. The pressure difference across the sand pack in single foam flooding and polymer-enhanced foam flooding both agree well with the simulation results. Based on the numerical simulation, the foam distribution characteristics in different cases were studied. The results show that there are three zones during foam flooding: the foam growth zone, stable zone, and decay zone. These characteristics are mainly influenced by the adsorption of surfactant, the gas–liquid ratio, the injection rate, and the injection scheme. The oil recovery of polymer-enhanced foam flooding is estimated to be 5.85% more than that of single foam flooding. Moreover, the growth zone and decay zone in three dimensions are considerably wider than in the one-dimensional model. In addition, the slug volume influences the oil recovery the most in the foam enhanced foam flooding, followed by the oil viscosity and gas-liquid ratio. The established model can describe the dynamic change process of foam, and can thus track the foam distribution underground and aid in optimization of the injection strategies during foam flooding. [ABSTRACT FROM AUTHOR]

Introduction: Post-traumatic osteoarthritis (PTOA) is an inflammatory condition that occurs following mechanical joint trauma and that results in joint degeneration. This study sought to evaluate the regulatory function of nuclear factor erythroid 2-related factor 2 (Nrf2) in a murine model of anterior cruciate ligament transection (ACLT)-induced PTOA and in an in vitro model of synoviocyte inflammation induced by LPS treatment with the goal of exploring the role of chitinase 3-like-1 (CHI3L1) in this pathogenic context. Methods: PTOA model mice were intra-articularly injected with Nrf2 overexpression lentiviral vector, and safranin O-fast green staining as well as the Osteoarthritis Research Society International (OARSI) Scoring System were used to evaluate the severity of cartilage damage. Protein expression in the synovial tissue was evaluated by Western blotting, immunohistochemical staining, and ELISA. Additionally, murine synoviocytes were infected with Nrf2 overexpression lentivirus and stimulated with LPS. The levels of inflammatory cytokines were detected by ELISA. ROS levels were measured using dihydroethidium (DHE) dye. Results: We determined that the overexpression of Nrf2 was sufficient to reduce cartilage degradation in the context of PTOA in vivo, and we observed a significant decrease in the expression of matrix metalloproteinase 13 (MMP13) in the articular cartilage of samples from mice overexpressing Nrf2 relative to control mice. Synovial CHI3L1 expression and serum TNF-α, IL-1β, and IL-6 levels were reduced in animals overexpressing this transcription factor relative to PTOA model controls. Consistent with these findings, murine synoviocytes treated with LPS exhibited dose-dependent increases in ROS, TNF-α, IL-1β, IL-6, Nrf2, and CHI3L1 levels, whereas Nrf2 overexpression was sufficient to suppress these increases. Conclusion: Our data indicated that Nrf2 negatively regulates CHI3L1, suggesting that this signaling axis may regulate PTOA progression and may thus be a viable therapeutic target in individuals affected by this condition. [ABSTRACT FROM AUTHOR]

When the depressurization development of a hydrate-bearing layer is initiated, the temperature of the near-wellbore formation quickly decreases to near the equilibrium temperature due to the dissociation of natural gas hydrate Therefore, the secondary generation of natural gas hydrates in the wellbore easily occurs if pressure jumps to a high value due to the changes of production rates or shutdown of the well. Though hydrate generation in the process of high-pressure drilling and gas and water transportation has been widely investigated, the secondary generation of natural gas hydrates caused by pressure jump during the depressurization development process is not fully understood. In this study, the multiphase pipe flow of a horizontal well, the Vyniauskas–Bishnoi generation dynamics of natural gas hydrate, and a decomposition dynamics model developed by Kim and Bishnoi are combined to build a set of horizontal well gas–liquid–solid three-phase flow models, which consider the phase transition in the wellbore and distinguished the secondary hydrate generation area in the wellbore under different temperature and pressure conditions. The results show that when the toe-end pressure is 7 MPa and the environment temperature is 6.4°C, the secondary hydrate generation exists in the horizontal section of the horizontal well, and the maximum hydrate flow velocity in the wellbore is 0.044 m3/d. A high toe-end pressure, low environment temperature, and high gas output will result in a greater hydrate generation in the wellbore, and the wellbore pressure will have a remarkable influence on the amount generated and its range. [ABSTRACT FROM AUTHOR]

In the oil development process, an immiscible third-phase slug can be injected to the formation temporarily to assist the water flooding, resulting in a three-phase flow underground. In this work, we study slug-assisted water flooding at the pore scale using the three-phase pseudopotential lattice Boltzmann model. We first briefly describe the three-phase pseudopotential model and propose a concise scheme to set the contact angles of the Janus droplet on the solid wall. Then, we simulate the slug-assisted water flooding process in different porous media structures, i.e., a single pore-throat channel, parallel throats, and a heterogeneous porous medium. The simulation results show that oil recovery can be improved effectively with the addition of the third-phase slug. The addition of the third phase results in much more interfacial interaction between different phases, which helps recover trapped oil in pore corners, narrow throats, and the high permeability zone in the porous medium. Moreover, the injection volume, injection timing, contact angle, and viscosity of the third phase influence the oil recovery in different ways. The injected slug can also be trapped in the porous medium, which may result in formation damage. The study explains the enhanced oil recovery mechanisms of slug-assisted water flooding at the pore scale and provides an effective way to design the injection scheme during industrial production. [ABSTRACT FROM AUTHOR]

Heat loss in wellbore during steam injection is considerable due to the deep burial of medium‐depth heavy oil reservoirs, leading to a low steam quality in the bottom of well. As for hot water flooding, the mobility ratio between oil and water is small, which decreases oil recovery. Flue‐gas foam assisted thermal‐chemical flooding is a new method for heavy oil reservoir. Compared to hot water flooding, flue‐gas foam assisted thermal‐chemical flooding can decrease oil viscosity, achieving higher sweep efficiency. However, the combined mechanisms of all the injected components have not been studied systematically. In this work, the role of CO2, viscosity reducer and hot water for oil viscosity reduction and distribution characteristics of residual oil were studied using the numerical simulation methods. Results show that although the percentage of viscosity reduction contribution of viscosity reducer can be as high as 60%, only wider range of this effect can help recover more remaining oil effectively. In the presence of flue‐gas foam, CO2 and viscosity reducer can decrease oil viscosity in the upper and bottom layers of the reservoir, respectively. Two parameters of the area proportion of removed‐oil (ARRO) and the average removed‐oil saturation (SDRO) are defined. It is believed that both ARRO and SDRO are quite small for the hot water flooding, which is assisted by viscosity reducer. The flue‐gas foam can obviously expand the area of removed‐oil, but the average removed‐oil saturation is slightly lower. The combination of flue‐gas foam and viscosity reducer is a promising displacement method. [ABSTRACT FROM AUTHOR]

After being injected into the porous media, the dispersion system of preformed particle gel (PPG) tends to enter high permeability regions and block water channeling passages, which forces the subsequent water to turn to the low permeability regions and thus increases sweep efficiency and enhances oil recovery. However, it is still unclear about the influence factors and the mechanisms how PPG increases water flow resistance, which limits the application of PPG in more oilfields. Therefore, the paper combines the lattice Boltzmann method (LBM), the discrete element method (DEM) and the improved immersed moving boundary (IMB) method to simulate the migration of deformable PPG in porous media. On the basis, the paper quantitatively analyzes the variation law of displacement pressure across the porous media and discusses the influence factors such as the PPG diameter, elasticity modulus and the number concentration. Results indicate that, because of the friction and retention of PPG in pore-throat, the displacement pressure across the porous media during PPG flooding is much higher than that during water flooding. In other words, the existence of PPG increases the flow resistance of injected water. Besides, the displacement pressure is always fluctuant resulting from the continuous process of PPG migration, retention, deformation and remigration. Influence factor analysis shows that the incremental value and fluctuation degree of flow resistance increase with the PPG diameter, elasticity modulus and the number concentration. The study not only provides useful reference for future PPG flooding, but also benefits the development of deformable particle flow theory. [ABSTRACT FROM AUTHOR]

Abstract: Foam flooding has become one of the most effective methods to improve oil recovery in high water-cut oilfields. In order to obtain images of the texture of foam in the cores under high pressure, this paper developed an experimental real-time image acquisition device for detecting the foam's texture as the bubbles flowed in the porous media. Image processing and statistic analysis methods for describing the foam's texture were also established. Experimental results showed that the bubble distribution became homogeneous and stabilized, and the pressure difference between two ends of the core increased gradually during the process of foam flooding. In the initial stage, the bubbles presented a flake-like distribution. The liquid phase flowed continuously, as did the gas phase. As the displacement continued, the volume of a single bubble lessened, while the number of bubbles increased. When the bubbles reached a steady state, the pressure difference between the two ends of the core was stable, and the bubbles presented a uniform distribution. A larger injection rate, a higher core permeability and a larger gas–liquid ratio all can cause a larger-than-average bubble diameter, poor stability and a decreased degree of homogeneity. [Copyright &y& Elsevier]

• A mathematical model of low-frequency electrical heating assisted depressurization (LF-EHAD) method is established. • The energy recovery behaviors from hydrate deposits with LF-EHAD are analyzed. • Gas production is significantly enhanced by electrical heating with a high energy efficiency ratio of 9.65. • The LF-EHAD method shows better production performance than hot water flooding. With the increasing global demand for clean energy, methane hydrate has been regarded as a potential alternative energy source in future due to its huge resources and high energy density. In this study, a mathematical model is established to evaluate the production performance of low-frequency electrical heating assisted depressurization (LF-EHAD) method for hydrate deposits recovery. Within the framework of this model, the integral finite difference method and Newton-Raphson iteration are employed for solution, which is then validated by the experiment data. Using this model, the energy recovery behaviors with LF-EHAD from Shenhu hydrate deposits are investigated and then compared with those performed by hot water flooding and depressurization. Simulation results show that hydrate dissociation and gas production are significantly enhanced as a result of sufficient heat supplied by the electrical heating, validating the potential of the LF-EHAD for hydrate deposits recovery. After 2000 days of production, the cumulative gas production of LF-EHAD and hot water injection are 2.37 times and 1.47 times of that conducted by the depressurization method. Moreover, the heat consumption used to increase the formation temperature in the hydrate dissociation region under LF-EHAD is much less than that of hot water flooding, which results in a higher energy efficiency ratio (EER) of 9.65 for LF-EHAD, while the EER of hot water flooding is 4.42. Overall, LF-EHAD shows better performance than hot water flooding with the same amount of heat input because of higher gas production and energy utilization efficiency, but lower water production. [ABSTRACT FROM AUTHOR]

Relative permeability curves in polymer flooding are important parameters to reflect the two-phase flow performance in reservoir rocks, which have important application in numerical simulation, reservoir engineering and prediction of crude oil production. Although the researches on the relative permeability curves in polymer flooding have made some progress at present, the relative permeability curves used in these researches are generally obtained by traditional experiment methods (steady-state method and unsteady-state method) or microscopic pore-scale modeling method. However, these methods are incapable of considering the physicochemical properties (i.e. rheology, residual resistance factor, adsorption and diffusion) of polymer completely. In this paper, a numerical inversion method based on automatic history matching is used to determine relative permeability curves in polymer flooding. The method performs automatic history matching by Levenberg-Marquardt (LM) algorithm on the unsteady-state experimental results and the predicted results of the numerical simulation model. As the physic-chemical properties of polymer solution have been fully taken into account in the numerical simulation model by far, the method makes up for the shortcomings of the traditional methods. Based on the inversed relative permeability curves, the effects of polymer viscosity and Darcy velocity in the rheo-thinning regime on relative permeability curves are then studied respectively. The results show that polymer viscosity and Darcy velocity in the rheo-thinning regime have little influence on the shape of oil relative permeability curve, but have obvious influence on the shape of water relative permeability curve. The deviation between the water relative permeability curve of polymer flooding and the one of water flooding increases linearly with the increase of polymer viscosity and decreases in power function with the increase of Darcy velocity in the rheo-thinning regime. At last, the prediction model of relative permeability curves under the influence of polymer viscosity and Darcy velocity in the rheo-thinning regime is established by multiple nonlinear regression method. The verification results show that this prediction model is reliable and can be used to predict the relative permeability curves at different polymer viscosities and Darcy velocities in the rheo-thinning regime. • Considering the effects of polymer physical properties in the inversion method. • Polymer affects water relative permeability by adsorption and high viscous force. • Darcy velocity affects water relative permeability by changing rheology of polymer. • Prediction model is available to gain polymer flooding relative permeability curve. [ABSTRACT FROM AUTHOR]