Optimizing of hydraulic fracturing design in unconventional gas reservoirs to mitigate the fracture and formation damages caused by conventional frac fluids
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In this dissertation, experimental studies were conducted to evaluate the impact of the fracturing additives on the fracture and near fracture face matrix of shale and low permeability sand formations. A simulation study was also conducted for optimizing of fracturing design to mitigate the problems of polymer adsorption and fluid blocking. New equations were developed for optimizing of fracturing additives based on the fluid shear rate and permeability during pumping. In comparison to the traditional “loss of fluid viscosity concept,” the new equations were more accurate and more representative of the damage in the fracture. Moreover, the new equations showed indicators about the impact of the fracturing additives on the fluid shear rate and fracture permeability. Flooding and spontaneous imbibition experiments, and analytical and simulation modeling were all integrated to evaluate the impact of the fracturing additives on the petrophysical properties of shale and low permeability sand samples. The results showed that for the low permeability sand samples, the polymer adsorption significantly reduces the brine permeability and fluid imbibition rate. However, the impact was less on the shale samples. Furthermore, the polymer adsorption led to a slight increase in capillary pressure. The non-ionic surfactant and dilute HCl acid improved the brine permeability and fluid imbibition rate. However, HCl treatment was affected by iron and polymer precipitates. The simulation study showed that the high shale capillary pressure could cause no fluid flowback from near fracture face matrix. The study recommended a dilute HCl acid in the pad stage, and little well shut-in times. For shales with moderate capillary pressure, considerable fluid flowback from near fracture face matrix occurs. A non-ionic surfactant and long well shut-in time are recommended for the fracturing design. However, to minimize the fluid loss during pumping and to overcome the problem of fluid blocking, it is recommended to use a friction reducer fluid in the pad stage while injecting a non-ionic surfactant or dilute acid during the subsequent fracturing steps. Finally, the fluid flowback was less for the cases of low reservoir pressure, incomplete fluid degradation, the presence of natural fractures, and permeability jail occurrence in the near fracture face matrix.