Hydraulic fracture networks, especially fracture geometry, height growth, and proppant transport within the networks, present a critical influence on productivity evaluation and optimization of fracturing parameters. However, information about hydraulic fracture networks in post-fractured formations is seldom available. In this study, the characteristics (density and orientation) of hydraulic fractures were obtained from field observations of cores taken from conglomerate hydraulic fracturing test site (CHFTS). A large number of fractures were observed in the cores, and systematic fracture description was carried out. The fracture analysis data obtained includes fracture density, fracture depth, fracture orientation, morphology, fracture surface features, apertures, fill, fracture mechanical origin (type), etc. Our results show that 228 hydraulic fractures were intersected in a span of 293.71 m of slant core and composed of irregularly spaced single fractures and fracture swarms. One of the potential sources of the observed fracture swarms is near-wellbore tortuosity. Moreover, for regions far away from the wellbore, reservoir heterogeneity can promote complex hydraulic fracture trajectories. The hydraulic fractures were mainly cross-gravel and high-angle fractures and align with maximum horizontal stress (S_Hmax) ± 15°. The fracture density, orientations, and types obtained from the core fracture description provided valuable information regarding fracture growth behavior. For the near-wellbore area with a transverse distance of less than 25 m from the hydraulically-fractured wellbore, tensile fractures were dominant. While for the area far away from the wellbore, shear fractures were dominant. Our results provide improved understanding of the spatial hydraulic fracture dimensions, proppant distribution, and mechanism of hydraulic fracture formation. The dataset acquired can also be used to calibrate numerical models and characterize hydraulic fracture geometry and proppant distribution.

Efficient proppant transport in conglomerate reservoirs is severely constrained by rough fracture surfaces and strong geometric heterogeneity, leading to premature near-wellbore deposition and insufficient distal support. To address this challenge, this study aims to clarify the transport and deposition mechanisms of proppants in rough-wall fractures representative of the Mahu conglomerate reservoir. A large-scale visualized physical simulation system with an artificial rough fracture (20 m length × 4.5 m height) was developed based on dynamic similarity principles, enabling long-distance proppant transport observation under controlled pumping rate, fluid viscosity, proppant size, and sand concentration. Ten systematic experiments were conducted, and real-time particle motion and sand ridge evolution were captured using high-speed imaging and pressure monitoring. The results show that proppants form longitudinally layered sand ridges that evolve through three stages: leading-edge initiation, equilibrium-height growth, and distal extension. Viscosity and sand concentration primarily control propped-area continuity, while pumping rate governs transport distance and particle size affects structural stability. Rough fracture surfaces significantly intensify near-wellbore accumulation by enhancing energy dissipation and local flow heterogeneity. These findings provide mechanistic insights into proppant transport in rough fractures and offer quantitative guidance for optimizing fracturing parameters in conglomerate reservoirs.

Multi-stage multi-cluster hydraulic fracturing in conglomerate reservoirs is often characterized by strong cluster-to-cluster variability in fluid distribution, which can reduce stimulation efficiency. However, field-scale observations that constrain how injected fluid is partitioned among clusters remain limited, especially in strongly heterogeneous formations. In this study, wide-field electromagnetic (WFEM) monitoring was applied to a horizontal well completed in the Baikouquan Formation sandstone–conglomerate reservoir of the Mahu Sag, Junggar Basin. The monitored treatment consisted of 13 fracturing stages, each containing six perforation clusters. Time-lapse electromagnetic data acquired during pumping were inverted to reconstruct the spatiotemporal evolution of the effective conductive fluid-swept region. Based on the inversion results, we introduce a set of quantitative proxy indicators (swept area, swept length, cluster-specific sweep, and an asymmetric index) to support relative comparison of fluid distribution patterns at both stage and cluster scales. Results show pronounced non-uniformity within and between stages, even under similar pumping conditions. A limited number of clusters exhibit stronger and farther-reaching WFEM-inferred conductive-fluid responses, whereas other clusters show weaker or more localized responses. Asymmetric sweep patterns on opposite sides of the wellbore are also commonly observed. These patterns are consistent with the combined influences of reservoir heterogeneity, local structural/stress disturbances, and operational factors, although WFEM alone does not uniquely validate causal mechanisms of fracture growth. Overall, this study demonstrates that WFEM monitoring provides a field-scale proxy tool for delineating effective conductive fluid-swept regions and for evaluating cluster-to-cluster variability under consistent acquisition and inversion settings. The findings offer practical guidance for interpreting fluid distribution and optimizing multi-cluster fracturing in strongly heterogeneous unconventional reservoirs.