Experimental study on fluid flow behaviors of waterflooding fractured-vuggy oil reservoir using two-dimensional visual model

Abstract

The carbonate reservoir plays a pivotal role in conventional oil and gas reservoirs. However, due to limited knowledge of fluid flow characteristics in fractured-vuggy carbonate formations (vuggy means a small to medium-sized cavity inside rock), high efficiency reservoir development remains challenging. In this study, the similarity principle is utilized to design a two-dimensional visual model based on geological data and the injection-production characteristics of a fractured-vuggy reservoir in M Oilfield. To investigate the characteristics of oil–water flow, the oil–water interface, and residual oil distribution, flooding experiments are conducted at various injection-production positions, types, and injection rates. The results suggest that a low injection/high production strategy is optimal for achieving maximum oil recovery. As a consequence, this configuration is employed in the subsequent flooding experiments. The optimal oil recovery of 82.2% is attained via pore injection and vug production. The Jamin effect exerts an influence on the oil-water flow in structures connected by small channels at the bottom of large vugs, necessitating adjustment of the flow rate to achieve optimal injection conditions. The variation of the oil–water interface height in each vug due to structural flaws results in suboptimal overall oil recovery. The oil recovery is limited to approximately 30% at an injection rate below 8 ml/min but can be enhanced to over 70% with a higher injection rate exceeding 8 ml/min. The residual oil of the fractured-vuggy reservoir is typically found in the tops of structures and peripheral areas with poor connectivity. The findings of this study offer direction for optimal production in fractured-vuggy carbonate reservoirs and facilitate a more comprehensive comprehension of oil–water flows within the reservoir.

Pore-Scale Transport Dynamic Behavior of Microspheres and Their Mechanisms for Enhanced Oil Recovery

“…Channeling of the injected fluid due to reservoir heterogeneity will reduce the swept fluid volume and reduce oil recovery. , No matter whether conventional or unconventional reservoirs − or gas − or water injection, plugging the dominant channels and expanding the swept volume of the injected fluid are the developmental ideas throughout the whole process of oil and gas field development . Additionally, due to the influence of reservoir wettability, the injected fluid tends to invade the pore throats with the least flow resistance under the action of a capillary force, which will also lead to the formation of dominant channels. , Therefore, the optimal selection of profile control agents and the revelation of their transport and plugging mechanisms in porous media are the focus of research. − …”

Experimental Study on Waterflooding Characteristics of a Large-Scale Physical Low-Permeability Model Based on a Similarity Criterion

“…While one-dimensional natural cores and cylindrical artificial cores offer improved simulation of formation heterogeneity conditions, their limited size prevents accurate and effective representation of fractured reservoirs. The 2D slab model, encompassing a visualized slab, microscopic glass etching models, and core slices, can also be replicated using crystal or resin materials to investigate fluid flow dynamics. − While the visual etching model offers the benefits of intuitive and real-time monitoring, it falls short in terms of consistent wettability characteristics between the solid phases of glass, resin, and reservoir rocks. Additionally, it lacks a comprehensive consideration of fracture morphology and faces challenges in accurately representing the remaining oil distribution after waterflooding in practical applications.…”