Matrix and fracture permeability of carbonate rich tight cores from Horn River basin Muskwa, Otter Park, and Evie shale formations were measured before and after exposing the core samples to spontaneous imbibition using dilute acid (1 or 3 wt. % HCl acid diluted in 10 wt. % KCl brine). Permeability and porosity were measured at varying net stress of 1,000 psia up to 5,000 psia. Brine and dilute acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiments observations: (a) formation damage due to water blockage of water-wet shales can be improved by adding dilute HCl acid or using hydrocarbon based fracturing fluids; (b) matrix permeability of clay rich or calcite poor shale samples are usually impaired / damaged by dilute acid imbibition; (c) matrix permeability and porosity of calcite rich of shales usually improved with dilute acid imbibition; (d) effective fracture permeability of unpropped calcite rich shales are reduced by dilute acid imbibition; this is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces". Nevertheless, dilute acid imbibition is less damaging than brine (slick water) imbibition; (e) acid injection instead of acid soaking/imbibition with proppant can optimize matrix permeability or Stimulated Reservoir Volume (SRV) of carbonate rich shales; (f) proppant embedment is caused by both brine (slick water) and dilute acid imbibition and can be minimized by resorting to low-concentration acid in such reservoirs; and (g) significant permeability and porosity hysteresis were observed due to proppant embedment during brine and dilute acid imbibition.

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