Abstract
In the Barnett Shale, microseismic bursts are caused by shear failure on planes of weakness well outside the central fracture plane. Some data show that greater gas flowrate is correlated with a larger "failed reservoir volume", and a higher net fracturing pressure. These aspects have been integrated into a theoretical model. Shear slip or failure along planes of weakness is instigated by pore pressure increases during injection of frac fluid, and pressure transient theory is used to describe that. A knowledge of in situ stress, and strength (or failure envelope) for the planes of weakness, is needed to predict how far away from the central fracture plane this failure zone extends. The failed reservoir volume can be matched to the volume of the microseismic cloud, using injection permeability is the matching parameter. The predictions appear to be reasonable. The injected permeability we obtain is greater than the virgin permeability, and this is interpreted as enhanced permeability due to shear or tensile failure away from the central fracture plane. The permeability enhancement increases as fracturing pressure increases. We have compared the permeability enhancement with history matching of gas production in Barnett Shale wells, and with theoretical matching of Cooper basin data in Australia. The model is a screening model, and may be viable to design a fracture treatment to optimize the enhanced permeability, and the gas production. An advantage of the screening model is its ability to quickly run a number of different scenarios, to choose an optimal stimulation. The model is completely general, and should be applicable to other formations, such as coals and tight sands.
