Oil and gas reservoirs dominated by coarse clastic rocks, particularly conglomerates (including gravel sandstones), are commonly termed conglomerate reservoirs in both the domestic and international literature. Sandy conglomerate reservoirs generally have high thickness and high productivity per unit area, but because of their characteristics such as rapid lithology change, strong heterogeneity, low porosity, and low permeability, it is difficult to develop conventional waterflooding. There is an urgent need for an efficient development scheme for the giant sandy conglomerate reservoir. In this study, nuclear magnetic resonance (NMR) technology was employed to investigate the stratified injection-production strategy for large-scale sandy conglomerate reservoirs. Three representative cores from different strata were selected to perform CO₂ flooding and CO₂-water alternating gas (WAG) flooding experiments, respectively. The aim was to explore how different development methods affect the recovery efficiency of various core types and the distribution of remaining oil under miscible and immiscible pressure conditions. The results show that immiscible CO₂ flooding mainly displaces crude oil in large pores, and oil in micropores and mesopores is difficult to displace. After gas channeling, there is still a large area of residual oil “aggregate” in the core, and the recovery rate is low. Compared with medium-coarse sandstone, the strong heterogeneity of sandy conglomerates leads to early gas breakthrough and low recovery efficiency during gas flooding. Compared with CO₂ flooding, CO₂-WAG flooding can balance the micro-oil displacement effect between micropores and macropores, significantly improve the oil production in micropores and mesopores. Thus, CO₂-WAG flooding has a certain micropore “profile control” effect, which can delay the gas channeling and improve the core recovery efficiency of reservoirs, especially for the highly heterogeneous sandstone. Miscible CO₂ flooding can effectively extract the oil in the mesopores and micropores that immiscible CO₂ flooding is difficult to displace. The gas breakthrough is slower and the recovery is much higher in miscible CO₂-WAG flooding than that of immiscible one. Therefore, ensuring that the formation pressure is higher than the minimum miscible pressure to achieve miscible flooding is the key to reservoir stimulation.

Complex narrow-channel reservoirs are strongly constrained by depositional architecture, resulting in highly nonuniform areal waterflood sweep, and pronounced water-cut variations among different channel types. These characteristics pose substantial challenges to stabilizing oil production and controlling water cut at high water-cut stages. To elucidate how narrow-channel planform architecture controls waterflood sweep, gel-assisted flow-field regulation by heterogeneous-phase composite flooding (HPCF), and remaining-oil mobilization, three representative configurations were reproduced in two-dimensional visual physical models. Sequential waterflood–HPCF–post-waterflood experiments were conducted, and time-lapse images and dynamic production data were integrated to characterize sweep evolution and remaining-oil mobilization across displacement stages. The results demonstrate that narrow-channel architecture exerts primary control on preferential flow-path development, gel migration and retention, spatial fluid redistribution, and displacement performance. During waterflooding, injected water preferentially migrated through high-permeability zones along channel centerlines, leaving channel margins, branch termini, and poorly connected regions insufficiently swept. After HPCF injection, the gel-containing composite system preferentially entered the established dominant flow paths. Gel retention and accumulation selectively increased flow resistance in these pathways, while mobility control induced subsequent fluids to divert toward bypassed regions, thereby enlarging the macroscopic swept volume and improving local displacement efficiency. A low injection rate promoted sustained gel-assisted flow diversion within bifurcated channels, whereas a high injection rate facilitated gel-slug propagation against the geometric constraints of highly sinuous channels and expanded its spatial coverage. Compared with waterflooding alone, HPCF increased the ultimate oil recovery of the three channel models by 19.23–26.47 percentage points. These findings clarify the coupled effects of narrow-channel architecture, gel transport and injection parameters on the profile-control and oil-recovery performance of HPCF, providing a mechanistic basis for water control and development optimization in high-water-cut narrow-channel reservoirs.