Distribution of Remaining Oil and Enhanced Oil Recovery Strategy for Carboniferous Buried-Hill Reservoirs in Junggar Basin

The Carboniferous reservoirs in the northwestern margin of the Junggar Basin exhibit complex lithological assemblages, primarily composed of siltstone, sandy conglomerate, tuff, and igneous rocks. These reservoirs are rich in oil and gas resources but have entered the middle to late stages of development. The reservoir spaces in the Carboniferous system are mainly composed of pores and fractures, resulting in a complex storage system. To provide effective strategies for stabilizing and enhancing production during the middle to late development stages, it is essential to establish a dual-porosity and dual-permeability model based on a clear understanding of lithological distribution patterns. This will facilitate the identification of favorable zones and the proposal of effective development strategies through numerical simulation. The present study systematically identified the lithology of the study area through microscopic lithological identification combined with logging data, conducted reservoir matrix property research under facies constraints, and established a three-dimensional geological model of lithology and physical properties. To more reasonably study the reservoir development process and establish an optimal development plan, a machine learning model for fracture density was trained using imaging logging interpretation results and conventional logging curve data. The model was then utilized to calculate single-well fracture density. Finally, a fracture model of the study area was established based on the collaborative constraints of fracture density and three-dimensional seismic attributes. Using the results of the established dual-porosity and dual-permeability model and production data, reservoir production evaluation and residual oil distribution research were conducted. The results indicate that the southwestern part of the study area features thick sandy conglomerate reservoirs with good physical properties, continuous lateral distribution, and high residual oil content, making it a dominant area favorable for horizontal well development and production. Additionally, reservoir numerical simulation was employed to study enhanced production development strategies. It is recommended to adopt gas–water alternating injection to improve production, with the optimal gas–water injection ratio of 4:1 yielding the maximum reservoir recovery factor. This study provides theoretical and technical support for the development of complex lithologic buried-hill reservoirs in the Carboniferous system of the western margin of the Junggar Basin.