In low-permeability reservoirs, studying reservoir sensitivity is crucial for optimizing water flooding, as it identifies detrimental mineral-fluid interactions that can cause formation damage and reduce injection efficiency. However, existing diagnostic methods for sensitivity-induced damage rely on post-facto pressure monitoring and lack a quantitative relationship between sensitivity factors and water injectivity impairment. Furthermore, correlating microscale interactions with macroscopic injectivity parameters remains challenging, causing current models to inadequately represent actual injection behavior. This study combines microscopic techniques (e.g., SEM, XRD, NMR) with macroscopic core flooding experiments under various sensitivity-inducing conditions to analyze the influence of reservoir mineral composition on flow capacity, evaluate formation sensitivity, and assess the dynamic impact on water injectivity. The quantitative relationship between clay minerals and injectivity impairment in low-permeability reservoirs is also investigated. The results indicate that flow capacity is predominantly governed by the type and content of sensitive minerals. In water-sensitive reservoirs, water injection induces clay swelling and migration, leading to flow path reconfiguration and water-blocking effects. In salt-sensitive formations, high-salinity water promotes salt precipitation within pore throats, reducing permeability. In velocity-sensitive formations, fine particle migration causes flow resistance to initially increase slightly and then gradually decline with continued injection. Acidizing generally enhances pore connectivity but induces pore-throat plugging in chlorite-rich reservoirs. Alkaline fluids can exacerbate heterogeneity and generate precipitates, though appropriate concentrations may improve connectivity. Under low effective stress, rock dilation increases porosity and permeability, while elevated stress causes compaction, increasing flow impedance.

To address the limitations of traditional chemical flooding—such as high cost, environmental impact, and formation damage—and the challenges of standalone microbial flooding—including preferential channeling, microbial loss, and limited sweep efficiency—this study develops a novel composite system for a high-permeability heavy oil reservoir. The system integrates a 3% scleroglucan + 1% phenolic resin gel (ICRG) with Bacillus licheniformis (ZY-1) and a surfactant. Core flooding and two-dimensional physical simulation experiments reveal a synergistic mechanism: The robust and biocompatible ICRG gel effectively plugs dominant flow paths, increasing displacement pressure fourfold to divert subsequent fluids. The injected strain ZY-1 then metabolizes hydrocarbons, producing biosurfactants that reduce oil–water interfacial tension by 61.9% and crude oil viscosity by 65%, thereby enhancing oil mobility. This combined approach of conformance control and enhanced oil displacement resulted in a significant increase in ultimate oil recovery, achieving 15% and 20% in one-dimensional and two-dimensional models, respectively, demonstrating its substantial potential for improving heavy oil production.