Prediction of fractures by using the stress field in medium to deep shale gas reservoirs: A case study of Late Ordovician–early Silurian shale gas reservoirs in the Nanchuan region, South China

Abstract

Containing representative shale gas reservoirs, the Wufeng–Longmaxi Formations in the Nanchuan region in South China have been modified by three compressional tectonic movements (in the Late Jurassic to Early Cretaceous, Late Cretaceous, and Cenozoic to present). These movements formed deeply buried reservoirs with complex in situ stresses and rapid directional changes, influencing the state of shale gas reservoirs fractures. Numerical modeling applied to model the stress field in the three periods showed that the maximum compressive horizontal principal stress (σHmax), strain rate, and fault slip rate regimes transformed from a thrust and strike-slip regime to a thrust and strike-slip regime to a thrust regime. The σHmax direction changed from NW–SE and WNW–ESE to WNW–ESE and nearly E–W and then to multiple directions. The magnitude of strain rate changed from -16 ∼ -15 to -17.7 ∼ -15.6 to -18.8 ∼ -15.8. The fault slip rate changed from 0 to 0.029 mm/a to 0–0.0026 mm/a to 0–0.0012 mm/a. These data strongly agree with data from drilled wells and outcrops and show that the present-day stress field is the superposed effect of multistage movements. Semiquantitative research was conducted on shale gas fracture openness and fracture development. Fracture openness is favorable when the angle between the σHmax direction and nearby faults is ≤45° and the distance from the fault is >2 km, and fracture development is favorable when the magnitude of the strain rate is <-17.6 and the fault slip rate is <0.00036 mm/a. Accordingly, we predicted fractured shale gas reservoirs.