Competitive Propagation of Multi-Cluster Fractures and Parameter Combination Optimization for Ball-Sealer Temporary-Plugging Fracturing in Deep Coal Seams

Competitive fracture propagation and the selection of temporary-plugging parameters are important challenges in multi-cluster fracturing of deep-coal horizontal wells. A three-dimensional discrete-lattice fluid–solid coupling model was employed to represent rock failure, fracture flow, dynamic wellbore–perforation–fracture flow allocation, and ball-sealer-induced diversion. Model performance was assessed through comparisons with an analytical solution for a penny-shaped hydraulic fracture and a field bottomhole-pressure record. The effects of plugging timing, ball-sealer placement ratio, and cluster spacing were evaluated through parameter comparisons and targeted plugging-time checks. The results show that plugging at 50% of the total injection time provides a favorable balance between fracture area and propagation uniformity. A reasonable range exists for the ball-sealer placement ratio, whereas excessive plugging can cause over-diversion and intensify fracture differentiation. Cluster spacing has a distinctly non-monotonic effect. Among 20 placement-ratio–spacing combinations evaluated at a fixed 50% plugging time, a 50% ball-sealer placement ratio and 25 m cluster spacing yielded a total fracture area of 793.26 m2 and a fracture-area differentiation coefficient of 0.0896. Additional timing checks favored the 50% plugging time among the three tested levels. In an observational comparison of two wells from the same block, the optimized well exhibited a 54.7% higher average daily gas production over the first 90 days; this difference cannot be attributed solely to the selected fracturing parameters. These findings provide conditional design guidance for multi-cluster temporary-plugging fracturing under the representative deep-coal stress conditions and simplified coal-rock assumptions investigated.