How does the connectivity of open-framework conglomerates within multi-scale hierarchical fluvial architecture affect oil sweep efficiency in waterflooding?

We studied the effects on oil sweep efficiency of the proportion, hierarchical organization, and connectivity of high-permeability open-framework conglomerate (OFC) cross-sets within the multi-scale stratal architecture found in fluvial deposits. Utilizing numerical simulations and the RVA/Paraview open-source visualization package, we analyzed oil production rate, water breakthrough time, and spatial and temporal distribution of residual oil saturation. The effective permeability of the reservoir exhibits large-scale anisotropy created by the organization of OFC cross-sets within unit bars, and the organization of unit bars within compound bars. As a result oil sweep efficiency critically depends on the direction of the pressure gradient. When pressure gradient is oriented normal to paleoflow direction, the total oil production and the water breakthrough time are larger, and remaining oil saturation is smaller. This result is found regardless of the proportion or connectivity of the OFC cross-sets, within the ranges examined. Contrary to expectations, the total amount of trapped oil due to the effect of capillary trapping does not depend on the pressure gradient within the examined range. Hence the pressure difference between production and injection wells does not affect sweep efficiency, although the spatial distribution of oil remaining in the reservoir depends on this value. Whether or not clusters of connected OFC span the domain does not affect sweep efficiency, only the absolute rate of oil production. The RVA/Paraview application allowed us to visualize and examine these non-intuitive results.

💡 Research Summary

This paper investigates how the proportion, hierarchical organization, and connectivity of high‑permeability open‑framework conglomerate (OFC) cross‑sets within the multi‑scale fluvial architecture of a reservoir influence oil sweep efficiency during waterflooding. Using three‑dimensional numerical simulations that explicitly represent the nested hierarchy of compound bars, unit bars, and cross‑sets, the authors varied the OFC volume fraction (5 %–30 %), the degree of connectivity (spanning versus non‑spanning clusters), and the direction and magnitude of the imposed pressure gradient. The simulations were coupled with the open‑source RVA/Paraview visualization suite to examine production rates, water breakthrough times, spatial and temporal evolution of residual oil saturation, and capillary‑trapped oil volumes.

Key findings are as follows:

1. Large‑scale anisotropy – The hierarchical placement of OFC cross‑sets within unit bars, and of unit bars within compound bars, creates a pronounced anisotropy in effective permeability. When the pressure gradient is aligned with the paleoflow direction, the high‑permeability pathways are parallel to flow, leading to rapid water breakthrough and lower overall sweep. Conversely, a pressure gradient oriented normal to paleoflow forces the injected water to cross the OFC channels, increasing the effective permeability in the transverse direction and improving sweep.

2. Direction of pressure gradient dominates – Across all examined OFC fractions and connectivity scenarios, waterfloods driven normal to paleoflow consistently yielded higher cumulative oil production, later water breakthrough, and lower residual oil saturation. This effect was robust to changes in the pressure difference between injector and producer (tested at 100, 300, and 500 psi).

3. Capillary trapping is pressure‑independent – The amount of oil immobilized by capillary forces remained essentially constant across the range of pressure gradients studied. This indicates that the capillary pressure contrast between OFC and the surrounding low‑permeability matrix governs trapping, and that modest changes in macroscopic pressure gradient do not alter the trapped volume.

4. Connectivity (spanning clusters) influences rate, not efficiency – Whether OFC clusters formed continuous pathways that spanned the entire model domain affected the early‑time production rate: spanning clusters produced oil more rapidly. However, the final sweep efficiency (fraction of original oil in place recovered) was virtually unchanged compared with non‑spanning configurations.

5. Pressure magnitude does not affect sweep efficiency – Increasing the pressure difference between injection and production wells accelerated the displacement front but did not change the ultimate amount of oil recovered. The spatial distribution of remaining oil did shift, with higher pressure gradients concentrating residual oil in different zones, but the integrated sweep efficiency remained the same.

The authors emphasize that these results run counter to the conventional intuition that higher pressure gradients or the mere presence of high‑permeability channels guarantee better recovery. Instead, the geometry of the fluvial hierarchy and the orientation of the pressure gradient relative to paleoflow are the primary controls. The RVA/Paraview visualizations were instrumental in revealing non‑intuitive flow patterns, such as water bypassing OFC channels when the gradient is normal to paleoflow, leading to more uniform sweep.

From an operational standpoint, the study suggests that optimal waterflood design in fluvial reservoirs should prioritize aligning injection‑production pairs so that the pressure gradient is transverse to the dominant paleoflow direction, rather than simply maximizing pressure differential. Moreover, while ensuring connectivity of high‑permeability OFC bodies can improve early production rates, it does not guarantee higher ultimate recovery. The insights provided here can guide field engineers in selecting well placement, injection strategies, and pressure management protocols to maximize sweep efficiency in complex fluvial systems.