RIASSUNTO
Abstract
Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.
Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.
This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.