The primary objective of this study is to investigate the evolution mechanism of carbon dioxide (CO₂) breakthrough pressure in mudstone caprock under different effective stresses. This study specifically investigates the silty mudstone caprock in the Bohai Bay Basin, China, and conducted a series of experiments on breakthrough pressure and permeability under different effective stresses. The evolution process of CO₂ breakthrough pressure in mudstone caprock was investigated, and the mechanism of pore water film affecting the breakthrough pressure was discussed. The results of this study illustrate that during the CO₂ injection process, the effective stress decreases from 27 MPa to 7 MPa, while the caprock permeability increases from 1.46×10⁻⁶ μm² to 1.81×10⁻⁶ μm². When the effective stress is 5.2 MPa, the minimum breakthrough pressure of caprock is 3 MPa, which exceeds the minimum sealing threshold of 2 MPa. The results of breakthrough pressure tests indicate that the caprock possesses effective sealing capability. The disjoining pressure and distribution characteristics of the pore water films are the main factors influencing the breakthrough pressure. The resistance of CO₂ transport increases with increasing the disjoining pressure of the water films, leading to high CO₂ breakthrough pressure. The pore throat radius of mudstone samples range from 0.1 nm to 2.5 nm in the Bohai Bay Basin, and the corresponding disjoining pressure of water films range from 5.2 MPa to 50 MPa. The water films has strong constraint ability on CO₂ migration.

The occurrence time and magnitude of injection-induced seismicity are influenced by engineering factors, such as wellhead pressure, injection location, injection volume, and injection rate. Understanding the relationship between injection operations and seismic magnitude is of great significance for optimizing industrial production and reducing earthquake disasters. Numerical simulation of hydro-mechanical coupling is a crucial method for studying injection-induced seismicity. However, few studies have explored the risk management measures for injection-induced seismicity from the perspective of engineering. How seismic magnitudes can be reduced through reasonable adjustments to injection operations in engineering remains unclear. Therefore, in this study, a 3D hydro-mechanical coupling model involving multiple faults and injection wells was established based on the geological background and well location of Fox Creek, Canada. Different injection schemes under multi-well and multi-fault conditions were studied, and a traffic light system was used to simulate and control the magnitudes under a multi-well injection scheme. Specifically, we simulated injection scenarios involving up to three wells and analyzed the response of five faults. We compared the maximum moment magnitude of different scenarios by controlling the same injection volume. The results revealed the effect and advantage of the multi-well scheme in reducing seismic magnitude. To reduce the risk of induced seismicity, utilizing far-fault operational wells to compensate for the effects of near-fault operational wells proves to be an efficient and cost-effective method, with potential for wide practical applications.

Nanofluids have broad prospects in enhancing the oil recovery of reservoirs with low porosity, low permeability, high capillary pressure and low oil recovery. However, the modification effects of nanofluids on tight glutenite reservoirs remain unknown. In this paper, nanofluids with different proportions of silica nanoparticles and sodium dodecyl sulfate were prepared and characterized by zeta potential and particle size distribution. Then, the effects of nanofluids on interfacial tension and reservoir wettability were examined. Next, a computational fluid dynamics method was adopted to further investigate the effects of nanofluids and injection pressure on enhancing oil recovery of the Baikouquan Formation at the pore scale. The experimental results showed that all prepared nanofluids are stable systems with uniform dispersion. The interfacial tension between the nanofluids and oil was reduced by up to 8.01% compared with water, and the reservoir wettability was changed from intermediate-wet to strong hydrophilicity. The simulation results revealed that the water and nanofluid flooding processes could be divided into two stages: the initial channel establishment stage and the channel expansion stage. In the initial stage, the nanofluids hardly showed an enhanced oil recovery effect due to the faster and sharper migration fronts. In the channel expansion stage, the nanofluids clearly showed an enhanced oil recovery effect, as the nanofluids could displace the oil in the relative dead pores during water flooding. After 10 pore volume injection of displacement fluid at an injection pressure of 1 MPa, the oil recovery using NF5 was highest at 76.58%. In addition, a higher injection pressure led to the extraction of relative dead oil at a lower injection pressure near the inlet with a smaller sweep area near the outlet; the effect on recovery has both advantages and disadvantages.