Polymer microspheres (PMs) are used as a new material to recover residual oil left in unswept oil areas after secondary recovery methods. The fact that the PMs plug the macropores causes the flow direction of the injection fluid to be transferred from macropores to micropores. In order to investigate the plugging and profile control mechanisms of PMs in reservoirs, four kinds of PMs with different particle sizes and four kinds of artificial cores with different permeability were selected for flooding tests, including plugging experiments and profile control experiments. The pore throat size distribution of cores was characterized by nuclear magnetic resonance (NMR) technology. The particle size distribution of PMs used in the experiment was characterized using a laser particle size analyzer. The results showed that there are six matching relationships existing simultaneously between pore throats and PMs based on theoretical analysis, which are completely plugging, single plugging, bridge plugging, smooth passing, deposition, and deformable passing. A key principle for optimizing PMs in profile control is that the particle size of the selected PMs can enter the high permeability layer well, but it is difficult for it to enter the low permeability layer. The results of this paper provide a theoretical basis for the optimal particle size of PMs during the oil field profile control process.

The brittleness index, as the most important parameter for brittleness evaluation, directly affects the compressibility of unconventional reservoirs. Currently, there is no unified calculation method for the brittleness index. This article uses a three-axis rock mechanics servo testing system to test the rock mechanics parameters of shale oil reservoirs in Block Y of the Ordos Basin and uses an X’Pert PRO X-ray diffractometer to test the rock mineral composition. The average volume fraction of quartz minerals, feldspar, and clay minerals in 36 samples of Block Y was tested to be 22.6%, 51.6%, and 18%, respectively. Calcite, dolomite, and pyrite are only present in a few samples. When the confining pressure is 30 MPa, the elastic modulus of the Chang 7 shale in this block is 14.72–34.58 GPa, with an average value of 23.77 GPa; The Poisson’s ratio ranges from 0.106 to 0.288, with an average of 0.182; The differential stress ranges from 100.8 to 260.1 MPa, with an average of 164.36 MPa; The peak strain ranges from 0.57 to 1.21, with an average of 0.91. This article compares several mainstream brittle index evaluation methods and identifies the most suitable brittle index evaluation method for Block Y. Using the Jarvie mineral composition method to calculate the brittleness index 1 (MBI), the average value of 36 experimental results is 0.5393. Using the Rickman normalized Young’s modulus and Poisson’s ratio average value to calculate the brittleness index 2 (EBI), the average value of 36 experimental results is 0.5204. Based on the stress-strain curve and energy method, a model for brittleness index 3 (DBI) is established, and the average value of 36 experimental results is 0.5306. The trend of the brittleness index calculated by the three methods is consistent, indicating the feasibility of the newly established brittleness evaluation method. From the perspectives of mineral composition, rock mechanics parameters, and energy, establishing a brittleness evaluation method for shale oil reservoirs and studying its evaluation method is of great significance for sweet spot prediction in reservoir engineering, providing theoretical support for the selection of fractured intervals in the Chang 7 shale oil reservoir in Block Y of the Ordos Basin.

The determination of rock mechanics parameters and in-situ stress during the development process of “horizontal well + volume fracturing” for shale oil reservoirs in Block Y of the Ordos Basin can provide a basis for fracturing schemes and production pressure difference design. Rock mechanics experiments are the most direct method for determining rock mechanics parameters. This article tested the in-situ stress of the Chang 7 shale oil reservoir in Block Y of the Ordos Basin through Kaiser acoustic emission experiments, calculated the static rock mechanics parameters of the block, and found that the vertical principal stress distribution of the Chang 7 section of the block is between 49.72 ~ 61.13 MPa, the maximum horizontal principal stress distribution is between 59.04 ~ 75.4 MPa, the minimum horizontal principal stress distribution is between 46.75 ~ 56.38 MPa, the horizontal stress difference is between 10.16 ~ 21.67 MPa, and the horizontal stress difference coefficient is between 0.21 ~ 0.42. The average maximum horizontal stress gradient is 2.534 MPa/100m, the average minimum horizontal stress gradient is 1.891 MPa/100m, and the average vertical stress gradient is 2.051 MPa/100m. In addition, dynamic rock mechanics parameters can be calculated using well logging curves, and a relationship model between dynamic and static rock mechanics can be established. Through calculation, the error can be obtained within 16%, which meets practical engineering requirements and can be applied in mining practice. The core experimental data is limited, discrete, and unable to reflect the trend of rock strength changes throughout the entire well section. By using logging curve data to predict rock strength parameters, continuous formation strength profiles can be obtained, providing important basis for later layer selection, section selection, and prediction of fracture direction.

The shale oil reservoir in Block Y of the Ordos Basin exhibits low porosity and low permeability, yet it features distinct stratification and developed micro-fractures. During the development process using “horizontal wells + volume fracturing”, the differential in geostress exerts a certain influence on the initiation and propagation of fractures. This paper employs the Cohesive element simulation method to investigate the formation patterns of fracture networks in fractured formations. By prefabricating natural fractures, the study explores the impact of natural fractures on the direction of hydraulic fractures during the hydraulic fracturing process. The study considers the fracture initiation and propagation patterns as well as the interaction between hydraulic fractures and natural fractures under differential geostress conditions of 0 MPa, 1 MPa, and 5 MPa. The numerical simulation results reveal that the presence of natural fractures significantly affects the direction of hydraulic fractures, with the tip of the hydraulic fracture deflecting towards the natural fracture. The smaller the geostress difference, the more complex the fractures become with more branching fractures. Conversely, a larger geostress difference leads to the formation of a single double-wing fracture perpendicular to the minimum principal stress, resulting in a simpler fracture morphology. The pore pressure variation at the injection point generally experiences a rapid increase followed by a slight decrease, subsequently undergoing wavy changes. The occurrence of wavy pressure variations indicates the continuous generation of micro-fractures. The fracture width at the injection point generally exhibits an increasing trend followed by a decreasing trend. When the stress difference is 0 MPa, 1 MPa, and 5 MPa, the peak rupture pressures are 12.63 MPa, 13.42 MPa, and 18.33 MPa, respectively; the maximum crack openings are 0.797 cm, 0.779 cm, and 0.771 cm, respectively. The study on fracture initiation and propagation in shale reservoirs provides guidance for the field application of multi-cluster fracturing in horizontal well sections.