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The shearing of pre-existing fractures plays an important role in the permeability enhancement of shale reservoirs during hydraulic fracturing or refracturing treatments. The process reactivates pre-existing fractures around a hydraulic fracture causing them to slip and dilate and can also cause fracture propagation in the shear and tensile modes creating secondary cracks resulting in increased permeability. However, laboratory data on fluid flow and fracture slip in reservoir rocks particularly shale rocks are rare, and the mechanisms of permeability evaluation with shear slip and dilation are still not well understood. In this work, we present the results of laboratory scale shear stimulation tests and numerical simulations to illustrate fracture permeability changes with fracture shear slip and complex network formation. Eagle Ford shale samples containing a natural fracture have been used to run triaxial shear tests and injection-induced shear tests. The multistage triaxial shear test has been performed to measure fracture mechanical properties including shear strength, friction angle, normal stiffness, and shear stiffness; the injection-induced shear test has been used to investigate fracture dilatant shear slip and the coupled permeability evolution. The multistage triaxial shear test show that this type of Eagle Ford fracture has a 37° friction angle, and average 1.39*106 psi/in. normal stiffness and 1.11*106 psi/in. shear stiffness. In the injection-induced shear test, we achieved 6 times increase in flow rate even with only a small induced shear sliding (<0.1 mm or <0.004 inch). Furthermore, permeability evolution during injection-driven shearing tends to linearly evolve with the shear slip and dilation. The irreversible behavior of shear slip was found to explain the permeability hysteresis during shear sliding. The relevant laboratory data has been used in numerical simulations to quantify the impact of shear slip along natural fractures during stimulation. This has been achieved using a newly developed complex fracture network model which robustly simulates hydraulic fracture propagation in a naturally fractured reservoir. The numerical results indicate that shear slip induced permeability enhancement in ultra-low permeability reservoirs is a critical component of stimulation particularly when most of the natural fractures are mechanically closed and may not be favorable for proppant placement.
Katsuki, Daisuke (Colorado School of Mines) | Deben, Anton Padin (Colorado School of Mines) | Adekunle, Olawale (Colorado School of Mines) | Rixon, Andrew J. (Colorado School of Mines) | Tutuncu, Azra N. (Colorado School of Mines)
SummaryA high-pressure triaxial compression cell has been utilized to study the stress-dependent permeability and dynamic elastic moduli in reservoir and seal shales. The testing assembly used is capable of characterizing tight shales in terms of permeability and ultrasonic wave velocities. The temperature was maintained at 40 oC with ±0.3 degree C of accuracy during the testing to minimize the influence of temperature disturbance on the measurements. The measurements have been carried out by increasing the net stress. The measurements have been carried out by increasing the net stress from 200 to 6,000 psi using dry nitrogen as the pore fluid. The Pierre seal shale sample contains approximately 60 percent of smectite clay, no organic composition and has higher porosity and permeability than the reservoir shale and was utilized as a reference shale for comparison. The reservoir shale is retrieved from a shale layer belonging to Eagle Ford containing 65 percent of calcite. The main components of clay of this shale is mica/illite and its mass content is 13 percent. The total organic carbon (TOC) content of the reservoir shale is 1 percent.
The experimental results indicated that the permeabilities of both reservoir and seal shales studied exponentially decrease with net stress. The stress sensitivity for the permeability of reservoir shale is three times greater than that of Pierre shale, although the permeability of reservoir shale is an order of magnitude lower than that of seal shale. The mechanism behind the stress sensitivities in shale permeability is discussed comparing stress sensitivity of the dynamic elastic properties for these shales.
Coupling pore fluid behavior and geomechanical properties of unconventional reservoir rocks is of great interest for developing reliable geomechanical models for comparing their behavior to the conventional reservoir rocks. Nano-scale complexities and heterogeneous pore distribution along with presence of various clay minerals and organic matter in reservoir shales complicate their geomechanical response changes in pore fluid pressure and other properties during completion and stimulation operations.
In nanopores, capillary pressure becomes high and promotes capillary condensation of the fluid phase (Bui et al., 2015). In addition, a change in the stress field in the reservoir rocks due to the disturbances from the drilling, hydraulic fracturing and production operations can largely affect the geomechanical properties. However, access to reliable stress-dependent permeability data in the reservoir shale formations coupled with their geomechanical behavior in the laboratory under in situ stress conditions is quite limited because of the high cost of retrieving core samples in addition to the expenses involved for their measurements.