This laboratory study, using formation cores, addressed problems associated with restoration of gas permeability in core from tight gas sand formations after massive hydraulic fracturing (MHF) treatments. Parametric studies affecting the flow of both brine and gas in these formation cores included the effects of the pressure differential across the fluid invaded zone, permeability, temperature, and gel damage to the fracture surface. Formation damage after exposure to fracturing fluids is primarily a problem of fluid recovery and water-saturation reduction.
Polymer damage to the fracture or fracture surface using Western tight gas sand cores caused significant brine permeability reduction and increased the fluid recovery time of the invaded zone. Increased fluid recovery time was magnified for very low permeability formations (less than 0.03 md) and low gas pressure differentials. Capillary end effects are postulated to be responsible for these results. However, after fluid saturations were reduced by displacement and evaporation, polymer damage to gas flow was less than 20 percent.
Results of this study indicate that as reservoir quality decreased there were greater capillary effects and extended time periods were required for invasion fluid recovery to attain maximum gas flow. By using cleanup time and regained gas permeability curves of saturated cores, these capillary effects were observable in the laboratory at reservoir conditions.