The application of horizontal well volume fracturing technology is an important method for enhancing oil recovery in tight oil reservoirs. However, the influence mechanism of the fracture placement scheme (FPC) on postfracturing productivity is still unclear. Based on the theory of the black oil model, combined with the reservoir stimulation characteristics of horizontal well volume fracturing in tight oil reservoirs, this paper established a postfracturing reservoir production simulation model. History fitting was used to verify the accuracy of the production model simulations. A series of numerical simulations was carried out to study the influence mechanisms of the fracture parameters and FPC on productivity. The simulation results show that compared with the fracture conductivity, the fracture length and number are the main parameters affecting tight oil reservoir productivity. Selecting a reasonable fracture length and number can realize the economical and efficient production of tight oil reservoir volume fracturing. Compared with the traditional fracture equal-length scheme, an FPC with an uneven fracture length can increase the cumulative oil production of oil wells. Under the condition of the same total fracture length, the scheme with a staggered distribution of long fractures and short fractures has the largest cumulative oil production over five years. A reasonable well spacing can greatly reduce the impact of interwell interference on postfracturing dual branch horizontal well productivity. When dual branch horizontal well fractures are alternately distributed, the postfracturing productivity is higher. The production simulation model established in this paper provides a method to accurately evaluate the productivity of horizontal wells after volume fracturing, which can provide guidance for the optimization of hydraulic fracturing operation parameters.

To address the unclear fracture propagation behavior and the insufficient understanding of the influence mechanisms of fracturing parameters during the hydraulic fracturing of deep coalbed methane reservoirs in the Yan’an Gas Field, Well JY1 in the No. 8 coal seam of the Benxi Formation in Block N was selected as the study object. An integrated three-dimensional geomechanics–fracture propagation model coupling geomechanical conditions, cleat characteristics, and fracture propagation was established. Fracture propagation simulations were conducted under different injection rates, fluid volumes per stage, and proppant volumes per stage. The results indicate that when main fractures intersect with cleats, they may exhibit deflection, branching, or direct crossing. Increasing the injection rate enhances the driving force at the fracture tip and improves the penetration capability of main fractures. Increasing the fluid volume improves fracture coverage and inter-cluster connectivity. Increasing the proppant volume contributes to greater residual fracture width, higher proppant placement concentration, and improved fracture conductivity. An injection rate of 19–21 m³/min, a fluid volume per stage of 2500–2700 m³, and a proppant volume per stage of 280–320 m³ provide a favorable balance between fracture network development and effective proppant support under the studied reservoir conditions.