Successful development of shale gas reservoirs is highly dependent on hydraulic fracture treatments. Many questions remain in regards to the geometry of the created fractures. Production data analysis from some shale gas wells quantifies a much smaller stimulated pore volume than what would be expected from microseismic evidence and reports of fracturing fluids reaching distant wells. In addition, claims that hydraulic fracturing may open or reopen a network of natural fractures are of particular interest.
This study examines hydraulic fracturing of shale gas formations with specific interest in fracture geometry. Field cases from the Horn River shale are analyzed using microseismic analysis as well as net pressure analysis of the fracture treatment. Fracture half lengths implied by microseismic events for some of the stages are several thousand feet in length. The resulting dimensions from microseismic analysis are used for calibration of the treatment model. The fracture profile showing created and propped fracture geometry illustrates that it is not possible to reach the full extent of the microseismic events given the finite amount of fluid and proppant that was pumped. The model shows that the created geometry appears to be much larger than half the well spacing. However, most of the fracture extent may be propped with 100 mesh proppant and the portion propped by 40/70 mesh may be about half the well spacing. From a productivity standpoint, the fracture will not drain a volume more than that contained in half of the well spacing. Fracture half-lengths greater than half the well spacing imply that the well spacing can be increased to ensure more economic development of the pad.
Optimization of hydraulic fracture treatments requires accurate information about the created fracture geometry. Previously published studies show that different analysis methods can lead to varying estimates of fracture geometry (Cipolla et al. 2009). Song et al. (2011) also showed that the hydraulic fracture size estimated from production data analysis for the Fayetteville and Haynesville shale formations was about 20% of typical horizontal well spacing. Extensive work has been done to evaluate microseismic monitoring as a technique to estimate fracture geometry. Neuhaus et al. (2012) presented a study from the Marcellus shale in which they linked microseismic analysis to an independent geological analysis. They observed that fracture propagation was dictated by the regional stress regime but also affected by the local geology. Detring and Williams-Stroud (2012) showed microseismic data from the Eagle Ford in which they observed the reactivation of pre-existing fractures. Maxwell et al. (2008) presented another case in which the microseismic events show how fracture propagation was affected by a pre-existing fault.