Quantifying Pressure Propagation and Oil Mobilization Across Fracture and Matrix Regions in a Hydraulically Fractured Shale Oil Well

Pressure propagation and oil mobilization across fracture and matrix regions during primary depletion remain poorly quantified in hydraulically fractured shale oil wells. A history-matched compositional model of Well H2CHF (Funing Formation, Subei Basin) simulated fracturing-fluid injection, shut-in, and production. The reservoir was partitioned along the oil-flow pathway into hydraulic fractures, stimulated matrix, and unstimulated reservoir, and the net oil withdrawal of each region was apportioned among drive mechanisms by material balance. Injection raised average pressure from 51.11 MPa to 75.15 MPa in the hydraulic fractures and 63.37 MPa in the stimulated matrix. After production began, pressure depletion propagated outward, leaving final pressures of 14.88, 16.37, and 21.23 MPa in the three regions, respectively. The stimulated matrix supplied 74.52% of the cumulative net oil withdrawal, whereas the hydraulic fractures served mainly as flow pathways. The recovery factor was 9.61%. In the two matrix regions, oil expansion, pore-volume contraction, oil displacement by fracturing fluid, and solution-gas drive contributed 61.73%, 13.13%, 10.69%, and 14.45%, respectively, and solution-gas drive dominated in the stimulated matrix during low-pressure depletion. Matrix permeability and retained fracture conductivity controlled pressure propagation, while the production schedule controlled pressure depletion. These results support region-specific production scheduling and pressure-support design.