In unconventional reservoirs, the initiation and propagation of multiple fractures are strongly influenced by the type of completion (number and type of initiation points). We conducted two hydraulic fracturing experiments in a laboratory setting on two blocks with different completion designs. Using field conditions for a tight sandstone reservoir, we used a scaling procedure to define confining stresses and pumping conditions (fluid viscosity and flow rate) that are optimal to mimic field propagation behaviors in a laboratory setting. The scaling procedure is based on rigorous hydraulic fracture mechanics principles, analytical expressions, and fully-coupled simulations. First, on LB1 block, we studied the initiation-propagation behavior using one stage with four circular notch-clusters, mimicking the first 40 min of the field propagation with 1 min of propagation in the laboratory. LB1 experiment led to the initiation and propagation of two fractures located on the first and last clusters, with one propagating to the edge of the block while the other one stopping quickly after initiation. Using pressure-time and acoustic emissions data, we observed excellent match between simulated and observed wellbore pressures, fracture radiuses and entering fluxes over time. Second, on LB2 block, we studied the fracture behavior using two one-cluster stages (with different injection rates) with multiple perforation-like entries azimuthally distributed in a 60-degree phasing configuration. Experiment LB2 showed a more complex initiation-propagation pattern than LB1 with non-planar transverse fractures initiating at multiple perforation locations for the top stage, leading to a primary fracture merged by a secondary following fracture. The acoustic emission observations, initiation pressures and entering fluxes were the most revealing features of this initiation complexity.
Over the past 15 years, the hydraulic fracturing technique has seen tremendous process and efficiency improvements in unconventional shale and tight-sand reservoirs, with the deployment of horizontal drilling and multistage hydraulic stimulation. However, there are still a number of critical mechanisms that need to be better understood for enhancing the design and execution of hydraulic stimulations, and subsequent production recovery. Among those critical issues are managing height growth, decreasing near-wellbore tortuosity, predicting and engineering complex network versus localized growth geometry, and promoting simultaneous growth of multiple hydraulic fractures (Bunger and Lecampion, 2017). In the laboratory, examples of experiments have recently focused on so called HF-NF interaction between natural and hydraulic fractures (Chuprakov et al., 2013; Zhang et al., 2015; Jeffrey et al., 2015; Bunger et al., 2016; Yang et al., 2016; Kear et al., 2017), on several initiation mechanisms (Lecampion et al., 2015, 2017; Winner et al., 2018; Lu et al., 2020; Zeng et al., 2020), or on novel sand-fiber proppants (Medina et al., 2018). Few experiments have studied the effect of well orientation, completion design, and rock fabric on near-wellbore hydraulic fracture geometry (Burghardt et al., 2015; Lecampion et al., 2015; Stanchits et al., 2015).
