Fracture Propagation, Fluid Flow, and Geomechanics of Water-Based Hydraulic Fracturing in Shale Gas Systems and Electromagnetic Geophysical Monitoring of Fluid Migration

Abstract

We investigate fracture propagation induced by hydraulic fracturing with water injection, using numerical simulation. For rigorous, full 3D modeling, we employ a numerical method that can model failure resulting from tensile and shear stresses, dynamic nonlinear permeability, leak-off in all directions, and thermo-poro-mechanical effects with the double porosity approach. Our numerical results indicate that fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics, whereas water saturation is determined by fluid flow. At early times, the water saturation front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with injected water. However, at late times, advance of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, which is filled with reservoir gas. We also find considerable leak-off of water to the reservoir. The inconsistency between the fracture volume and the volume of injected water cannot properly calcuate the fracture length, when it is estimated based on the simple assumption that the fracture is fully saturated with injected water. As an example of flow-geomechanical responses, we identify pressure fluctuation under constant water injection, because hydraulic fracturing is itself a set of many failure processes, in which pressure consistently drops when failure occurs, but fluctuation decreases as the fracture length grows.We also study application of electromagnetic (EM) geophysical methods, because these methods are highly sensitive to changes in porosity and pore-fluid properties due to water injection into gas reservoirs. Employing a 3D finite-element EM geophysical simulator, we evaluate the sensitivity of the crosswell EM method for monitoring fluid movements in shaly reservoirs. For this sensitivity evaluation, reservoir models are generated through the coupled flow-geomechanical simulator and are transformed via a rock-physics model into electrical conductivity models. It is shown that anomalous conductivity distribution in the resulting models is closely related to injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for distribution of injected fluids (i.e., migration pathways) during hydraulic fracturing operations.

Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

“…However, as shown in Kim et al (2014), hydraulic fracturing of shale gas reservoirs may be affected by complex two-phase flow processes, including vertical gravity segregation within the created fractures. To investigate these effects Kim et al, (2014) conducted a hydraulic fracturing simulation of a shale-gas reservoir for the extreme cases of water saturated and gas saturated rock, and achieved similar radial extent of the stimulated fracture. Thus, we would not expect any major extension of the calculated rupture zone if considering some initial gas saturation in 30 m thick gas bearing formation.…”

“…Nevertheless, the study in Kim et al, (2014) shows that the created fracture volume may not be equal the injected volume due to two-phase flow effects and fluid leak-off to the surrounding rock. Here, we injected 2160 m 3 (571,611 gallons) of water over the 3-hour injection, which can be considered a typical average injection volume per fracturing stage (e.g., compared with data shown in Mayerhofer et al (2011) and BC Oil and Gas…”

Finite-element analysis of top-casing electric source method for imaging hydraulically active fracture zones

“…Because of the high contrast of electrical conductivity between the prism and the background geology, the high concentration of the electrical current preferentially flows along the surface of the prism and directly charges HAFZ. We consider that the high-pressure injection of saline fluid creates HAFZ (Kim et al, 2014). HAFZ is created perpendicular to the horizontal well and 200m away from the vertical well.…”

“…To ensure the sufficient sensitivity of the methods to deep HAFZ, one can consider injecting highly-conductive saline fluid or fluid with electromagnetically contrasting tracers (e.g. Moridis and Oldenburg, 2001;Rahmani et al, 2014;Kim et al, 2014). Such fluid and tracers can raise the magnitude of weak anomalous signals from HAFZ to a detectable level.…”

Investigation of possible wellbore cement failures during hydraulic fracturing operations

“…From Kim et al (2014), the pressure at the injection point is between 30MPa and 40MPa after early time fracturing. Then, considering pressure drop between the injection point of the horizontal well and the bottom hole at the vertical well, 30MPa of the bottom hole pressure of the vertical well is assumed to be reasonable as a reference case.…”