Polymer microspheres are one type of particle gel with swelling property, and the particle size is distributed between nanometer and micron. Because of the good variability and migration characteristics, polymer microspheres are widely used as conformance control agents, especially in fractured reservoirs. However, in the application process, the matching between polymer microspheres and the size of reservoir fractures remains insufficiently studied, leading to prevalent blind applications and low utilization efficiency. Based on polymer microspheres with different elastic modulus (23.6–715 Pa) prepared in the laboratory, the swelling dynamics of polymer microspheres were established according to their swelling ratio data under different reservoir temperatures (20–80 ℃). The fracture plate model was used to simulate the fractured reservoir, the matching mechanism of polymer microspheres in the model was studied. Applying this model and equation p_t = kGʹ + m, we further investigated the quantitative relationship between threshold pressure and elastic modulus of polymer microspheres in the fracture plate model in the migration process. The swelling ratio of polymer microspheres showed that the polymer microspheres absorbed water quickly in the early stage and gradually slowed down in the later stage. The characteristics of the early stage were simulated by Fickian equation and those of the later stage were simulated by Schott equation. A new swelling kinetic equation of polymer microspheres was established considering the whole swelling characteristics. The diameter/width ratio was used as an evaluation index, the matching property results showed that under the experimental conditions, the migration modes of microspheres in the fracture plate model were straight-through passage, deformable passage, and blockage. Under the same elastic modulus, the smaller the fracture aperture, the higher the threshold pressure. At the same fracture aperture, the threshold pressure increased with the increase in elastic modulus. Based on the obtained results, the value range of threshold pressure under different fracture apertures could be quantitatively predicted, and then the particle size and elastic modulus of the polymer microspheres for conformance control could be determined according to the reservoir fracture parameters. The blind use of polymer microspheres for conformance control agents should be avoided, the success rate of fractured reservoir of conformance control could be improved. The results of the study have experimental guidance for the conformance control scheme design of polymer microspheres.

CO₂ flooding enhanced oil recovery (CO₂-EOR) represents a significant technology in the low permeability reservoir. With the fractures and heterogeneity in low permeability reservoirs, CO₂-EOR is susceptible to pessimistic gas channeling. Consequently, there is a need to develop conformance control materials that can be used in CO₂-EOR. Herein, to address the challenges of low strength and poor stability of polymer gel in high temperature and low permeability reservoirs, a new organic/metal ion composite crosslinking polymer gel (AR-Gel) is reported, which is formed by low hydrolysis and medium to high molecular weight polymer (CX-305), organic crosslinking agent (phenolic resin), and aluminium citrate (Al(Ⅲ)). The crosslinking of Al(Ⅲ) with carboxyl group and organic/metal ion double crosslinking can construct a more complex and stable polymer gel structure on the basis of traditional chemical crosslinking, to cope with the harsh conditions such as high temperature. The structure–activity relationship of AR-Gel was revealed by rheology behavior and micro-morphology. The applicability of AR-Gel in reservoir was investigated, as was its strength and stability in supercritical CO₂. The anti-gas channeling and enhanced oil recovery of AR-Gel were investigated using low permeability fractured cores, and the field process parameters were provided. The gel can be used to meet supercritical CO₂ reservoirs at 110 °C and 20,000 mg/L salinity, with long-term stability over 60 days. The plugging rate of AR-Gel for fractured core was 97%, with subsequent CO₂ flooding resulting in an enhanced oil recovery by 34.5%. AR-Gel can effectively control CO₂ gas channeling and enhanced oil recovery. It offers a new material with high strength and temperature resistance, which is particularly beneficial in the CO₂ flooding for the conformance control of oil field.

CO₂ flooding is a vital development method for enhanced oil recovery in low-permeability reservoirs. However, micro-fractures are developed in low-permeability reservoirs, which are essential oil flow channels but can also cause severe CO₂ gas channeling problems. Therefore, anti-gas channeling is a necessary measure to improve the effect of CO₂ flooding. The kind of anti-gas channeling refers to the plugging of fractures in the deep formation to prevent CO₂ gas channeling, which is different from the wellbore leakage. Polymer microspheres have the characteristics of controllable deep plugging, which can achieve the profile control of low-permeability fractured reservoirs. In acidic environments with supercritical CO₂, traditional polymer microspheres have poor expandability and plugging properties. Based on previous work, a systematic evaluation of the expansion performance, dispersion rheological properties, stability, deep migration, anti-CO₂ channeling and enhanced oil recovery ability of a novel acid-resistant polymer microsphere (DCNPM-A) was carried out under CQ oilfield conditions (salinity of 85,000 mg/L, 80 ℃, pH = 3). The results show that the DCNPM-A microsphere had a better expansion performance than the traditional microsphere, with a swelling rate of 13.5. The microsphere dispersion with a concentration of 0.1%–0.5% had the advantages of low viscosity, high dispersion and good injectability in the low permeability fractured core. In the acidic environment of supercritical CO₂, DCNPM-A microspheres showed excellent stability and could maintain strength for over 60 d with less loss. In core experiments, DCNPM-A microspheres exhibited delayed swelling characteristics and could effectively plug deep formations. With a plugging rate of 95%, the subsequent enhanced oil recovery of CO₂ flooding could reach 21.03%. The experimental results can provide a theoretical basis for anti-CO₂ channeling and enhanced oil recovery in low-permeability fractured reservoirs.

Oil displacement by spontaneous imbibition is a capillary-governed process, in which wettability controls fluid displacement direction. Capillarity is a driving force to enhance oil displacement in water-wet system, while in oil-wet system capillarity is a resisting one. To promote oil displacement, the former requires high capillarity, but the latter opposes. Such requisites are hypothesized to be alternatively achieved by manipulating an oil-water interfacial tension, without altering wetting character. In this study, spontaneous imbibition was conducted with a set of specifically designed imbibing fluids. Brines at different valencies were meticulously selected to attain desired wettabilities: monovalent brine establishes a water-wetting while divalent brine provides an oil-wet characteristics. A non-ionic surfactant, Triton X-100, was intentionally chosen to solely reduce interfacial tension, with negligible change in wettability. By mixing each brine with the surfactant, high-interfacial tension and low-interfacial tension imbibing fluids at the same wettability for the two wetting regions were obtained, and hence the hypothesis can be examined. For water-wet system, reduced interfacial tension attributed to a weakened driving capillary force to oil displacement, and hence lower oil displaced. On the contrary in oil-wet system, reduction in resisting capillary force as contributed from a reduced interfacial tension displaced greater oil. The results demonstrate how the capillary-driven fluid displacement can be manipulated by the interfacial tension change only, without a challenge of altering wettability. With results obtained from both wetting regions, a correlation between capillarity and ultimate oil displacement was also observed.