Micromodels have been widely used to visualize surfactant flooding, which provides new insights into understanding pore-scale events during displacement. In this review, recent advances in micromodel studies of surfactant flooding are briefly summarized. The mechanisms of surfactant flooding as demonstrated by micromodel studies are presented, as well as pore-scale findings that cannot be captured by traditional coreflood methods.

Drainage displacement at unfavorable viscosity ratios is often encountered in oil recovery, CO₂ sequestration, and NAPL remediation, which significantly limits recovery of fluids from porous media. Surfactants have been extensively used as wettability modifiers to improve hydrocarbon recovery from rock matrix by imbibition. But little attention has been paid to the effect of surfactant‐assisted wettability alteration on displacement in non‐fractured porous media. In this study, we investigate surfactant‐assisted immiscible displacement in NAPL‐wet microfluidic chips. We find that the change of advancing contact angle by surfactant is velocity dependent. A stable displacement can be achieved at low velocity when wettability‐altering surfactant solution is used as injection fluid. In comparison, fingering occurs at all capillary numbers for water injection, resulting in low NAPL recovery. The generation of NAPL ganglion during waterflooding is significantly different from that during wettability‐altering surfactant flooding. The generation of NAPL ganglion during wettability‐altering surfactant flooding is related to velocity and saturation due to the wettability alteration and interfacial tension reduction. In contrast, the production of NAPL ganglion during waterflooding is only saturation dependent. NAPL ganglia generated during wettability‐altering surfactant flooding are primarily within the pore‐size range and can be easily recovered in subsequent recovery processes. To the best of our knowledge, this study reveals for the first time the pore‐scale mechanism of surfactant‐assisted wettability on the immiscible displacement, which is important for highly efficient NAPL remediation.

Although technical advances in hydraulically fracturing and drilling enable commercial production from tight reservoirs, oil/gas recovery remains at a low level. Due to the technical and economic limitations of well-testing operations in tight reservoirs, rate-transient analysis (RTA) has become a more attractive option. However, current RTA models hardly consider the effect of the non-uniform production on rate decline behaviors. In fact, PLT results demonstrate that production profile is non-uniform. To fill this gap, this paper presents an improved RTA model of multi-fractured horizontal wells (MFHWs) to investigate the effects of non-uniform properties of hydraulic fractures (production of fractures, fracture half-length, number of fractures, fracture conductivity, and vertical permeability) on rate transient behaviors through the diagnostic type curves. Results indicate obvious differences on the rate decline curves among the type curves of uniform properties of fractures (UPF) and non-uniform properties of fractures (NPF). The use of dimensionless production integral derivative curve magnifies the differences so that we can diagnose the phenomenon of non-uniform production. Therefore, it’s significant to incorporate the effects of NPF into the RDA models of MFHWs, and the model proposed in this paper enables us to better evaluate well performance based on long-term production data.

Summary: The integration of fracturing, energy enhancement, and imbibition (IFEI) has proven successful in shale oil development, with one of the keys to enhancing development efficiency lying in improving imbibition effectiveness during the well shut-in phase. Carbonated water (CW) imbibition effectively combines the advantages of CO2 and water for enhanced oil recovery. Nevertheless, research on its performance in shale oil reservoirs remains scarce, and its application in fracturing has not been investigated. This study, for the first time, proposes using CW as a dispersion medium in the formulation of carbonated fracturing fluid to enhance IFEI development in shale oil. Computed tomography (CT) online scanning experiments were specifically designed to investigate the countercurrent imbibition distance (CID) and recovery (CIR) across various fluids, including formation water, nanovariable viscosity slickwater (NVS) fracturing fluids, and the newly formulated carbonated fracturing fluid. Additionally, separate imbibition experiments were carried out to assess the overall imbibition recovery of these fluids, focusing on exploring various factors influencing the imbibition of carbonated fracturing fluid. CT scans reveal that carbonated fracturing fluid significantly enhances imbibition performance, achieving a CID of 1.75 cm and a CIR of 6.95%. Compared with formation water and NVS fracturing fluids, it exhibits increases in CID by 0.75 and 0.25 cm, and improvements in CIR by 4.77 and 1.90%, respectively. Further insights from the imbibition experiments demonstrate that carbonated fracturing fluid achieved the highest recovery at 29.28%, surpassing NVS fracturing fluids (25.17%) and formation water (10.21%). Enhanced imbibition recovery was facilitated by elevated CO2 content, higher temperatures, and increased matrix permeability. Correlation analysis reveals that among the parameters selected, CO2 content exerts the most significant influence, followed by permeability, with temperature having the least impact. This study offers novel insights into the efficient development of shale oil through IFEI and the use of CW.

Polymer flooding plays an important role in enhanced oil recovery (EOR), particularly in China, where partially hydrolyzed polyacrylamide (HPAM) and hydrophobically associating water-soluble polymers (HAWP) are used in onshore and offshore reservoirs, respectively. Many researchers have highlighted the elasticity of HPAM, which can be used to improve the sweep efficiency, i.e., the ratio of the area swept by an injected fluid to the oil area. On the other hand, fewer studies exist on the elasticity of HAWP. In this study, we investigate the flow of HAWP and Xanthan solutions with identical viscosities in core experiments in terms of elasticity; results reveal that the HAWP can produce shear thickening in the core. The constitutive equation for the HAWP can be obtained using the simulation results matched with the experimental data. On the basis of these experiments, we established a two-phase flow model of a polymer and oil, including the continuity, momentum, constitutive, and phase equations. The volume-of-fluid (VOF) method was used to track the interface between the two phases. A complex pore model was established based on the glass-etched model used in the experiment. We used the OpenFOAM platform to solve the mathematical model. The saturation, pressure, and stress tensor distributions were obtained. The results show that the displacement efficiency increased as the elasticity of the polymer increased; accordingly, the elasticity can enlarge the sweep area and decrease the residual oil saturation. As the elasticity increases, the stresses (the first normal stress, second normal stress, and shear stress) increase. Finally, the results obtained in this study can be used as a guideline in polymer design, screening, and optimization in the polymer flooding oilfields.

The polymer flooding process has already been applied to the medium permeability type II reservoirs of the Daqing Oilfield (China) to enhance oil recovery. However, this process faces a number of challenges, such as the flooding efficiency, high injection pressure, formation blockage and damage, unbalanced absorption ratio, and economical justification. In this study, single-phase and two-phase flow experiments are performed to investigate polymer injection adaptability with natural cores of type II reservoirs. The enhanced oil recovery (EOR) effects of the polymer are studied by physical simulation experiments, and the results of application in an actual field are also presented. The results indicate that the flow characteristics and injection capability are dominated by the reservoir permeability in polymer flooding. Moreover, the adsorption of polymer molecules and the injection pressure gradient, which reflect formation damage, are affected more significantly by the concentration than by the molecular weight in type II reservoirs. Using the matching relationship, the injection-production process is stable, and additional oil recoveries of 10%–15% can be obtained in heterogeneous type II reservoirs with a high water saturation. This work is significant in that it further accelerates the application of polymer flooding EOR in medium permeability heterogeneous oilfields with high water saturation.