The propagation behavior of hydraulic fracture network in a reservoir with cemented natural fractures

Abstract

AbstractThere are still some problems in the study of hydraulic fracture (HF) network evolution in cemented naturally fractured reservoirs, such as microseismic mapping showing exaggerated stimulated reservoir volume in some cases. In addition, the dominant role of natural fracture (NF) cementation strength, injection rate, in situ stress difference, NF distribution, and fracture initiation sequence of perforations in synthetically influencing fracture network formation needs to be further studied. For this purpose, a three‐dimensional matrix hexahedral element global coupled 0‐thickness cohesive element hydraulic fracturing model was developed. Results show that each interaction between HF and NF causes HF diameter shrinkage, which increases the propagation pressure of HF. When the cementation strength of the NF is low, the HF tends to deviate toward the tip of the NF to form a complex fracture network. Increasing the injection rate and the number of NFs can significantly enhance the complexity of the HF network, but does not change the HF and NF interaction pattern. The in situ stress differences dominate the morphology of the HF network when the cementation strength of NFs is constant. The stress interference of multiple fractures under segmented fracturing may form “S”‐shaped HFs, and the HFs are difficult to maintain a symmetrical morphology in the direction of the well axis. In addition, some NFs in inactivated damaged zones have developed a certain width geometrically due to the induced effect of HF, but they are still isolated by the low permeability matrix and might only generate some microseismic events.