Principal Stress or Large-Scale Natural Fracture/Fault—What Dictates the SRV of Deep Shale Gas Reservoirs: Perspective from the Southern Sichuan Basin

Abstract In-situ stress is generally regarded as one of the most crucial factors controlling hydraulic fracture characteristics. Fracture propagation is expected to be perpendicular to the minimal horizontal stress. However, microseismic monitoring results of deep shale gas reservoirs in the Sichuan Basin indicate that the stimulated reservoir volume (SRV) shows various propagation patterns and asymmetric geometry. The growth of SRV is not strongly related to the minimal principal stress direction. In deep shale, high principal stress difference reduces fracture complexity, while the well-developed natural fractures/faults further complicate the fracture propagation process. In this study, we examine what dictates the SRV of deep shale gas reservoirs via field data, experimental results, and numerical simulation results analyses. Microseismic monitoring data from different fractured horizontal wells penetrated and surrounded by large-scale natural fractures/faults are analyzed by comparing the detected events with natural fracture/fault interpretation maps. In the experiment review, the cubic and cylindrical samples were cut from shale outcrops similar to the target formation rock. The pumping rate ranges from 9.78 to 45 mL/min. The highest horizontal principal stress difference can reach 17 MPa. The resulting fracture geometry is revealed by opening the samples for fracture description and performing 3D reconstruction. Results show that the microseismic data points tend to overlap with the interpretated natural fractures/faults, indicating that hydraulic fractures are arrested by natural fractures/faults. This phenomenon causes overstimulation along the large-scale natural fractures/faults, making the rest of reservoir volume unstimulated. The azimuth of the stimulated reservoir volume (SRV) is also consistent with natural fracture/fault azimuth. Here, the large-scale natural fractures/faults serve as major conduits for fracturing fluid flow, inducing fracture hits and well interactions, and reducing the stimulation efficiency. Small-scale fractures that are not interpreted in the fracture/fault interpretation map make the fracture geometry become more complex than bi-wing-planar fractures. In the case where the natural fractures/faults are parallel to the horizontal wellbore, T-shaped data point distribution can be observed, suggesting that parallel natural fractures/faults significantly limit the expansion of SRV. If the hydraulic fracture is not connected to the above types of natural fractures, microseismic monitoring results indicate that a simple primary hydraulic fracture is likely to be created due to the high horizontal principal stress difference. For the experiments, without natural fractures, hydraulic fractures appear to propagate simply along the maximum horizontal stress direction even the horizontal principal stress difference is zero. Hydraulic fracture propagation is dominated by natural fractures for samples with preexisting fractures. Increasing the pumping rate and lowering fluid viscosity may not able to generate complex fracture networks as well. If the frac-refrac strategy is applied, the local stress state can be changed, leading to the enhancement of fracture complexity. Numerical simulation results show that the increment in horizontal principal stress simplifies the fracture geometry even the main fracture connects existing natural fractures. The findings of this study allow for optimization of fracturing treatment design in deep shale gas reservoirs.