Numerical Analysis of Complex Fracture Propagation Under Temporary Plugging Conditions in a Naturally Fractured Reservoir

Abstract

Summary Temporary plugging during fracturing operations has become an efficient method to create a complex fracture network in tight reservoirs with natural fractures (NFs). Accurate prediction of the network-propagation process plays a critical role in plugging- and fracturing-parameter optimization. In this paper, the interaction between one single hydraulic fracture (HF) within a temporary plugging segment and multiple NFs was simulated using a complex fracture-development model. A new opening criterion for an NF penetrated by a nonorthogonal HF already was implemented to identify the dominant propagation direction of a HF under plugging conditions. Fracture displacements and the induced-stress field were determined by the 3D displacement-discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of an NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by an HF within the plugging segment, the HF tends to propagate along the NF branch inclined in the main HF direction. The farther the interaction position is away from the HF tip, the easier the NF with an approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the effect of plugging, fluid pressure in the HF plummets at the beginning of the NF opening and keeps decreasing until the NF extends for a certain distance or encounters secondary NFs. Fluid-pressure drop occurs mainly in the unturned NF, together with the width of unturned NF being significantly lower than that of the turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid-pressure distribution, affecting the network progress under the temporary plugging conditions are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging-segment length. The simulation results provide critical insight into complex fracture-propagation progress under temporary plugging conditions, which should serve as guidelines for well choosing and plugging optimization in temporary plugging fracturing.

Fracturing Fluids and Their Application in the Republic of Croatia

“…Lu et al (2020) conducted a numerical simulation using a complex fracture development model where the interaction between one single hydraulic fracture within a temporary plugging segment and multiple natural fractures was observed. The numerical results demonstrated that the opening and development of a natural fracture are mainly dominated by its approaching angle and relative location [13].…”

“…An increasingly important segment of the industry is currently stimulating naturally fractured formations (e.g., tight sands and shales); where the assumptions of linear elasticity, simple fluid leakoff, and planar geometry fail to hold [10][11][12][13][14][15]. Temporary plugging during fracturing operations has become an efficient method to create a complex fracture network in tight reservoirs with natural fractures.…”

“…Temporary plugging during fracturing operations has become an efficient method to create a complex fracture network in tight reservoirs with natural fractures. An accurate prediction of the network propagation process plays a critical role in the optimization of the plugging and fracturing parameters [13].…”

Experimental Investigation of the Growth Law of Multi-Fracture during Temporary Plugging Fracturing within a Stage of Multi-Cluster in a Horizontal Well

“…Correspondingly, it is difficult to achieve the economic and efficient development of shale oil and gas resources. Therefore, the secondary reservoir stimulation is required to improve the fracture complexity and increase the stimulation volume, accordingly increasing the production in a single well [3,4]. The temporary plugging fracturing is an important technique to improve the fracture network stimulation efficiency of the re-fracturing in shale reservoirs [5,6].…”

Ball sealer tracking and seating of temporary plugging fracturing technology in the perforated casing of a horizontal well

“…The ultimate goal is to adequately divert the stimulated fluids into the reservoir (Erbstoesser, 1980). One major obstacle that limits the success of temporary plug fracturing technology has been the inability to use a ball sealer to seal the targeted perforation hole at the exact moment (Li et al, 2020;Lu et al, 2019). Hence, it is urgent to study the entire movement process and seating performance of ball sealers after their descent into the wellbore.…”