For the Tahe Oilfield, there are multiple sets of karst reservoirs with different genesis developed in carbonate fracture-vuggy reservoirs and the varying karst reservoir type has a considerable influence on the distribution of residual oil. The complex characteristics of different karst reservoirs and the difficulty in producing the remaining oil in the middle and lower part of the reservoir greatly restrict the recovery effects. This work managed to comprehensively investigate the action mechanism of nitrogen-assisted gravity drainage (NAGD) on remaining oil in reservoirs with different karst genesis through modeling and experiments. Based on geological characteristics and modeling results, a reservoir-profile model considering reservoir type, fracture distribution, and the fracture–cave combination was established, the displacement experiments of main reservoirs such as the epikarst zone, underground river, and fault karst were carried out, and the oil–gas–water multiphase flow was visually analyzed. The remaining oil state before and after NAGD was studied, and the difference in recovery enhancement in different genetic karst reservoirs was quantitatively compared. The results show that NAGD was helpful in enhancing oil recovery (EOR) for reservoirs with different karst genesis. NAGD technique has the greatest increasing effect on the sweep efficiency of the fault-karst reservoir, followed by the epikarst zone reservoir, and the smallest in the underground river reservoir. The results of this research will facilitate an understanding of the EOR effect of karst-reservoir types on NAGD and provide theory and technical support for the high-efficiency development in varying karst reservoirs in the Tahe Oilfield.

Fractured-vuggy reservoirs are a new target in carbonate oil and gas exploration and development. Because of well-developed reservoir bodies, including fractures and caverns, bottom water invasion can be observed in oilfield development, with low utilization efficiency of crude oil in the reservoir. Accordingly, this study focused on the intersection region of the S99 unit of the Tahe fractured-vuggy reservoirs. Based on seismic data, the reservoir bodies can be divided into three types—caverns, fractures, and broken solution pores. Using the same location condition assignment algorithm, four single-type models are fused into a multi-scale discrete three-dimensional geological model of fractured and cavernous reservoirs, and the corresponding fractured-vuggy reservoir model was established for numerical simulation. The single-well historical fitting precision exceeded 85%. Furthermore, the development can be divided into four stages—initial stage of production, peak production stage, liquid control and oil stabilization stage, and scale gas injection stable. Streamlining sweep analysis determined the utilization and distribution characteristics of the remaining oil in the reservoir. It can be concluded that structure, caverns, and fractures were the main controlling factors affecting the remaining oil distribution in the fractured-vuggy reservoir. The fluid exchange among single-well reserve zones was calculated using streamline-based quantitative sweep analysis and interwell flow quantitative analysis method. Through source-sink quantitative analysis, interwell flow relations were derived, and three water breakthrough modes were further concluded: violent flooding, slow ascending of water cut, and low cut or intermittent water production.

Identifying and categorizing drilling-induced fractures is pivotal for understanding the mechanisms underlying wellbore instability, drilling fluid loss, and assessing reservoirs using imaging logging data. This study employs a linear elastic stress model around the wellbore, coupled with a tensile failure criterion, to establish a predictive framework for the orientation of drilling-induced fractures. It investigates how engineering parameters like wellbore trajectory and bottomhole pressure influence the distribution of principal stresses around the wellbore, as well as the angle and orientation of drilling-induced fractures relative to the wellbore axis, across various faulting scenarios. The results indicate that drilling-induced fractures exhibit structured arrangements and consistent patterns, often appearing at approximately 180° symmetric intervals and descending in similar orientations. This provides a theoretical basis for their systematic identification and classification. Under different stress conditions, these fractures can manifest as feather-like shapes, “J”-shaped, or transitional states between feather-like and “J”-shaped orientations, as well as “V”-shaped or “M”-shaped orientations. Accurate detection and classification of these fractures are essential for interpreting effective fractures, conducting thorough reservoir evaluations, and predicting appropriate drilling fluid densities to mitigate the wellbore failure risk. Moreover, this knowledge aids in effectively determining the magnitude and direction of in situ stress inversion.

To verify the predictive accuracy of existing strength criteria on true triaxial strength experimental data, understand the characteristics of different strength criteria, and provide a basis for selecting strength criteria for engineering applications, ten commonly used rock strength criteria were selected and divided into MC and HB types. The distribution characteristics of the yield surfaces and yield curves of different criteria were compared and analyzed in the principal stress space and the π plane. Afterwards, based on the least absolutely deviation method, these ten strength criteria were used to predict 32 sets of true triaxial rock strength experimental data. The results showed that the range of undetermined parameters for MC type strength criteria was small and easy to determine, while the range of undetermined parameter for HB type criteria was large and difficult to determine the search range, in addition, the fitting process may not converge. The fitting accuracy of strength criteria for true triaxial experimental data depends on the sensitivity of rock strength to the intermediate principal stress. PH and GP criteria are the most sensitive to changes of the intermediate principal stress, followed by MWC and ML criteria, MGC and ZZ criteria, MCJP and HBWW criteria. PH and GP criteria overestimate the effect of the intermediate principal stress, resulting in the largest prediction errors, while the other three-dimensional strength criteria have high prediction accuracy and no significant differences. The research results can provide scientific basis for engineering design, geological hazard prediction, and mineral resource development.