Volumetric estimates provide a valuable check on the estimates derived from material balance and decline analysis methods. Xinli-Xinbei oilfield, Jilin Province-China is an ascertained and developed oilfield. It is affluent in geological reserves, and has greatly development potentiality. Based on the high precision of tridimensional reservoir geological model, this study calculated the reserves of the Xinli-Xinbei oilfield by Petrel, which deal with the issue that the reserves parameters are difficult to correctly acquire when estimate complex reservoir's reserves in terms of traditional volume method. In addition, the achievement maps made by Petrel show the distribution of reserves more accurately. Consequently, the results indicated that application of Petrel in reserve estimation reflects the true nature of the reservoir more accurately and more objectively which can better be applied to oilfield development and adjustment.

Absolute permeability is a key index for evaluating the fluid transmission capacity of sandstone reservoirs. However, what determines its value is not just the pore volume itself, but also whether the effective flow-transmission space is formed, whether the dominant throats are unobstructed, and whether the pore network organization is favorable for flow connectivity. In this paper, we take 20 1 mm × 1 mm × 1 mm digital sub-samples cropped from the fixed CT field of view of 5 parent sandstone samples as the research object. Based on X-ray micro-CT, we built digital core models, finished pore space characterization, pore structure parameter extraction and single-phase seepage simulation with Avizo software, and used the geometric mean of three-directional absolute permeability, k_g, to characterize the overall seepage capacity of the sub-samples. The results show that the 20 digital sub-samples present obvious differences in pore space development degree, effective flow-transmission space scale, dominant throat size and network topology organization, with k_g ranging from 8.684 to 62.350 × 10^- 15 m². Total porosity shows a significant positive correlation with k_g overall, but under similar porosity conditions, the permeability can still differentiate further. Further redundancy elimination screening indicates that, after controlling for connected porosity, the median throat radius still retain a statistically detectable incremental explanatory effect, whereas Euler number also preserved an additional but more marginal contribution within the current dataset, with partial correlation coefficients of 0.466 ( P = 0.038) and 0.447 ( | r |, P = 0.048), respectively. Under the current sample system and unified processing conditions, the differences in absolute permeability of millimeter-scale digital sandstone sub-samples can be interpreted primarily by connected porosity, median throat radius, and Euler number, which correspond to three complementary aspects: effective flow-transmission space, dominant channel size, and network organization. However, the incremental contribution of Euler number should be understood with appropriate caution under the present sample size.

Pore-scale heterogeneity is an important consideration in the evaluation of heavy-oil reservoirs. The aim of this study was to reconstruct CT-based digital cores of four plug samples, characterize their pore structures, and analyze single-phase flow behavior, in order to clarify how pore geometry and segmentation control the computed porosity and permeability. Four plug samples (two glutenite and two pebbly sandstone) from the Guantao Formation of the D84 Block, Liaohe Depression, were investigated using X-ray micro-computed tomography (micro-CT) with an isotropic voxel size of 9.37 μm. Three-dimensional digital cores were reconstructed through image preprocessing and interactive threshold segmentation. CT-derived porosity, volume-weighted equivalent-diameter distributions of labeled pore objects, and axial porosity variability were analyzed. Single-phase flow simulations were performed in PerGeos to estimate permeability and visualize streamline and pressure distributions. The CT-derived porosities ranged from 27.37% to 32.92%, whereas the simulated permeabilities ranged from 1009 to 1477 mD. ZS-1 exhibited the lowest CT-derived porosity but the highest simulated permeability, indicating that bulk porosity alone did not fully account for variations in simulated flow behavior among the four samples. The simulated permeabilities were lower than the laboratory-measured values, with relative differences ranging from 10.6% to 52.4%. These differences highlight the influence of image resolution, segmentation, and differences between numerical and experimental conditions on image-based permeability estimation. The study provides a sample-scale characterization of pore structures and single-phase flow behavior in the investigated reservoir material.