Study on Formation and Migration Law of Foam in Fractures and Its Influencing Factors.

This study focuses on the characteristics of foam generation, flow, and plugging in different reservoir fracture environments. Through visual physical model experiments and stone core displacement experiments, we analyze the flow regeneration of foam in a simulated reservoir fracture environment as well as its sealing and sweeping mechanisms. The findings reveal that low permeability reservoirs, with their smaller and more intricate fracture structures, are conducive to the generation of high-strength foam. This is due to the stronger shear effect of these fracture structures on the injected surfactant and gas mixture system, resulting in a denser foam system. Consequently, low permeability reservoirs facilitate a series of mechanisms that enhance the fluid sweep efficiency. Furthermore, the experiments demonstrate that higher reservoir fracture roughness intensifies the shear disturbance effect on the injected fluid. This disturbance aids in foam regeneration, increases the flow resistance of the foam, and helps to plug high permeability channels. As a result, the foam optimizes the injection-production profile and improves the fluid sweep efficiency. Stone core displacement experiments further illustrate that during foam flooding, the foam liquid film encapsulates the gas phase, thereby obstructing fluid channeling through the Jamin effect. This forces the subsequently injected fluid into other low-permeability fractures, overcoming the shielding effect of high-permeability fractures on low-permeability fractures. Consequently, this improves the fluid diversion rate of low permeability fractures, effectively inhibiting fluid cross-flow and enhancing sweep efficiency. These experimental results highlight the advantages of foam flooding in the development of complex reservoirs with low permeability fracture structures, demonstrating its efficacy in inhibiting fluid cross-flow and optimizing the injection-production profile.

Nanofluids of Amphiphilic Kaolinite-Based Janus Nanosheets for Enhanced Oil Recovery: The Importance of Stable Emulsion.

To meet the increasing global demand for energy, better recovery of crude oil from reservoirs must be achieved using methods that are economical and environmentally benign. Here, we have developed a nanofluid of amphiphilic clay-based Janus nanosheets via a facile and scalable method that provides potential to enhance oil recovery. With the aid of dimethyl sulfoxide (DMSO) intercalation and ultrasonication, kaolinite was exfoliated into nanosheets (KaolNS) before being grafted with 3-methacryloxypropyl-triemethoxysilane (KH570) on the Alumina Octahedral Sheet at 40 and 70 °C to form amphiphilic Janus nanosheets (i.e., KaolKH@40 and KaolKH@70). The amphiphilicity and Janus nature of the KaolKH nanosheets have been well demonstrated, with distinct wettability obtained on two sides of the nanosheets, and the KaolKH@70 was more amphiphilic than the KaolKH@40. Upon preparing Pickering emulsion in a hydrophilic glass tube, the KaolKH@40 preferentially stabilized emulsions, while the KaolNS and KaolKH@70 tended to form an observable and high-strength elastic planar interfacial film at the oil-water interface as well as films climbing along the tube's surface, which were supposed to be the result of emulsion instability and the strong adherence of Janus nanosheets towards tube's surface. Subsequently, the KaolKH was grafted with poly(N-Isopropylacrylamide) (PNIPAAm), and the prepared thermo-responsive Janus nanosheets demonstrated a reversible transformation between stable emulsion and the observable interfacial films. Finally, when the samples were subjected to core flooding tests, the nanofluid containing 0.01 wt% KaolKH@40 that formed stable emulsions showed an enhanced oil recovery (EOR) rate of 22.37%, outperforming the other nanofluids that formed observable films (an EOR rate ~13%), showcasing the superiority of Pickering emulsions from interfacial films. This work demonstrates that KH-570-modified amphiphilic clay-based Janus nanosheets have the potential to be used to improve oil recovery, especially when it is able to form stable Pickering emulsions.

Microscopic Mechanical Model Analysis and Visualization Investigation of SiO2 Nanoparticle/HPAM Polymer Foam Liquid Film Displacing Heavy Oil.

In this paper, the microscopic mechanisms and macroscopic characteristics of polymer/nanoparticle foam flooding in a heavy oil reservoir environment were studied. Sodium dodecyl sulfate (SDS) surfactant was used as the foaming agent, and the foam was prepared by a combination of partially hydrolyzed polyacrylamide (HPAM) polymer and SiO2 nanoparticles. By performing experiments with the microscopic model, the foam flooding dynamics in the heavy oil reservoir were simulated. Based on the experiments, the formula model was established to evaluate the physicochemical effects between the foam liquid film and oil surface. Finally, the macroscopic characteristics of foam flooding were studied by performing oil displacement experiments with a 2D visual model. The microscopic experiments demonstrated that the foam liquid film could exert multiple actions, such as adsorption, stretching, and cutting on the heavy oil in the reservoir pores. These actions were accompanied by force changes between the foam and heavy oil, and the addition of polymer and nanoparticles further strengthened them. The calculations of the formula model indicated that the polymer and nanoparticles amplified the force between the foam liquid film and heavy oil by 1.95 and 2.2 times, respectively. The 2D visual model experiments suggested that foam flooding could further develop heavy oil after water flooding through its liquid film effects, and the oil recovery efficiency increased from 42.43 to 57.82%. In addition, the polymer and nanoparticles further optimized the oil displacement effect of the foam liquid film, which made the oil recovery efficiency reach 64.77-68.16%.

Experimental Investigation on Microscopic Force Measurement of Foam and Heavy Oil.

This paper combined experiments with a theoretical model to simulate the behavior between a foam and heavy oil during contact pressing, separation, and adsorption. We discuss the changes in the elasticity and adsorption forces during the pressing and adsorption of the two fluids. The influence of the changes in temperature and pressure, the concentration of the sodium dodecyl sulfate surfactant, the heavy oil viscosity, and the addition of partially hydrolyzed polyacrylamide and hydrophobic SiO2 nanoparticles was studied. The results showed that the overall increase in the elasticity and adsorption forces between the foam at 1 wt % surfactant and heavy oil was more than 2 times greater than those of the foam with 0.2 wt % surfactant. The increase in viscosity of heavy oil also increased various forces. The overall improvement in the adsorption force between fluids caused by nanoparticles during separation and adsorption stages reached 1.8 times, which was better than that obtained using the polymer (1.65 times). However, the polymer showed a 1.4 times higher elastic force during the fluid pressing stage than the nanoparticles and about 4 times higher than the control foam, and the increase in temperature greatly weakened the effect of the force, while the change in pressure did not cause much impact. An analytical model was built based on fluid mechanics, and the calculation results were consistent with the experimental data with an error of about 5-12%, suggesting that this model provides a good reference value.

Investigation of the Effect of Nanoparticle-Stabilized Foam on EOR: Nitrogen Foam and Methane Foam.

In recent years, studies conducted on foam stabilization have focused on nanoparticles by generating strong adsorption at the interface to stabilize the foam under harsh reservoir conditions. Meanwhile, the selection of a gas source is also of great importance for foam performance. In this study, a mixed system of surfactants was selected, and the foamability and foam stability of nitrogen and methane were evaluated according to the improved jet method. After adding modified SiO2 nanoparticles, the foam-related parameters were analyzed. The plugging abilities of the different foams were compared through core-flooding experiments, and the oil displacement effects of the different foams were compared through microfluidic experiments. The results show that the amphoteric surfactant betaine has an excellent synergistic effect on the anionic surfactant SDS. The methane foam produced using the jet method has a larger initial volume than the nitrogen foam, but its stability is poor. The half-life of the nitrogen foam is about two times that of the methane foam. After adding 1.0 wt % SiO2 nanoparticles to the surfactant solution, the viscosity and stability of the formed foam improve. However, the maximum viscosity of the surfactant nanoparticle foam (surfactant-NP foam) is 53 mPa·s higher than that of the surfactant foam. In the core-flooding experiment, the plugging performance of the methane foam was worse than that of the nitrogen foam, and in the microfluidic experiment, the oil displacement abilities of the methane foam and the nitrogen foam were similar. The plugging performance and the oil displacement effect of the foam are greatly improved by adding nanoparticles. The surfactant-NP foam flooding has a better oil displacement effect and can enhance the recovery factor by more than 30%. Under actual high-pressure reservoir conditions, although the stability of the methane foam is weaker than that of the nitrogen foam, some methane may be dissolved in the crude oil to decrease the viscosity after the foam collapses, which leads to the methane foam being the preferred method in oilfields.