## 7 Conclusions  
Utilizing reservoir geological modeling technology, this study constructed a physical parameter model that captures the intrinsic characteristics of the reservoir. The adoption of PetrelTM 3D geological modeling software(version 2018) was instrumental in enhancing the model's precision. The employment of sedimentary facies control techniques, alongside sequential indicator simulation and sequential Gaussian simulation, enabled a more accurate depiction of the lithofacies and properties. The geological probability surface constraint method was used to better show the regularity of physical property changes in the center and edge of the sand body, and to more directly reflect the distribution characteristics of channel sediments. The increase in constraint conditions further improved the accuracy of the model and reduced the uncertainty and randomness of inter-well interpolation to a certain extent. Especially when the reaction of the reservoir's physical properties is  
Figure 13: Histogram of frequency distribution of lithofacies, porosity, and permeability of the Chang 7 member in the southern Heshui block.  
changed, the advantages of phase-controlled modeling are reflected, and it can better meet the needs of the next stage of oilfield development.  
The lithofacies model reveals that the continuity of sand bodies within the Chang 7 member is more pronounced in the direction of provenance than perpendicular to it. Influenced by the microfacies control of the distributary channels, these sand bodies exhibit extensive, continuous distributions in the mid-northwest and southwest regions. In the vertical plane, the presence of large box-shaped sand bodies, formed by the stacked accumulation of multi-stage distributary channel sands, is notable. However, the intercalated mudstone layers are modestly developed, exhibiting slightly poorer continuity in the longitudinal direction.  
The attribute model shows that the Chang 7 member reservoir is a typical type of extremely low porosity and permeability. The porosity of the Chang 7 sandstone shale oil reservoir ranges from 1.27% to 15.04%, with an average of 8.47%. The normal distribution is obvious, and the majority of ultra-low pores account for more than 88%. The permeability is mainly distributed in the range of 0.001-1 mD, with an average of 0.74 mD, and the correlation between porosity and permeability in the same layer is good. The porosity is primarily distributed from the southwest to the northeast, aligning with the extension direction of the sandstone in the lithofacies model. High-value areas of porosity are concentrated in the south and west of the central study area, although they are relatively small and dispersed. These high-value zones correspond well with regions of thicker sand bodies, indicating favorable zones for development within the study area.  
Conceptualization, L.W.; Methodology, L.W. and S.L.; Formal analysis, S.L.; Writing--original draft, L.W.; Writing--review & editing, L.W. All authors have read and agreed to the published version of the manuscript.  
This research received no external funding.  
Not applicable.  
The authors declare no conflict of interest.