The tight conglomerate oil reservoir in Xinjiang’s Mahu area is situated on the northwestern margin of the Junggar Basin. The reservoir comprises five stacked fan bodies, with the Triassic Baikouquan Formation serving as the primary pay zone. To delineate the study scope and conduct a field validation, the Ma-X well block was selected for investigation. Through triaxial compression tests and large-scale true triaxial hydraulic fracturing simulations, we analyzed the failure mechanisms of tight conglomerates and identified key factors governing hydraulic fracture propagation. The experimental results reveal several important points. (1) Gravel characteristics control failure modes: Larger gravel size and higher content increase inter-gravel stress concentration, promoting gravel crushing under confining pressure. At low-to-medium confining pressures, shear failure primarily occurs within the matrix, forming bypassing fractures around gravel particles. (2) Horizontal stress differential dominates fracture geometry: Fractures preferentially propagate as transverse fractures perpendicular to the wellbore, with stress anisotropy being the primary control factor. (3) Injection rate dictates fracture complexity: Weakly cemented interfaces in conglomerates lead to distinct fracture morphologies—low rates favor interface activation, while high rates enhance penetration through gravels. (4) Stimulation strategy impacts SRV: Multi-cluster perforations show limited effectiveness in enhancing fracture network complexity. In contrast, variable-rate fracturing significantly increases stimulated reservoir volume (SRV) compared to constant-rate methods, as evidenced by microseismic data demonstrating improved interface connectivity and broader fracture coverage.

Fine migration is widely recognized as a primary cause of production decline in unconsolidated sandstone reservoirs. Migrated fines may accumulate within pore throats and obstruct flow channels, or they may be transported into the wellbore with the produced fluids, leading to operational issues such as wellbore plugging, pump sticking, and equipment abrasion. Despite extensive studies on fine migration, the role of particle wettability has received limited attention. In this study, the mineralogical composition of formation particles was first characterized using X-ray diffraction (XRD) and quantitative clay analysis. Surface modification experiments were then conducted to investigate the effect of hexadecylamine (HDA) on particle wettability and to determine the optimal reaction conditions. Surface characterization techniques were employed to elucidate the modification mechanism. Subsequently, sand-packed tube displacement experiments were performed to evaluate the influence of wettability alteration on fine migration behavior. The underlying mechanisms were further interpreted through interfacial thermodynamic analysis. Two potential field application schemes are proposed to facilitate practical implementation in oilfield operations. The results indicate that the water contact angle of formation particles increased from 0° to 150° when treated with 0.8 wt% HDA for 24 h. Surface characterization confirms that HDA molecules were physically adsorbed onto the particle surfaces. Displacement experiments demonstrate that the permeability reduction rate decreases significantly with increasing particle hydrophobicity. Thermodynamic analysis suggests that the work of adhesion on the modified particle surface was reduced by 93.3%, thereby weakening fluid–particle interfacial coupling and suppressing fine mobilization. This study provides a wettability-based approach for mitigating permeability damage caused by fine migration in unconsolidated sandstone reservoirs.