As part of a Department of Energy (DOE)-sponsored program, an optimal thermodynamic pathway to transform natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid has been already developed. Using NG foamed fracturing fluids reduces the enormous water requirements for stimulation by as much as 60% to 80% and poses benefits for productivity in water-sensitive formations. This study aims to extend the investigation to characterize the hydraulic fracture geometry and quantify the expected production when using an NG foam fracturing fluid. Using validated models, we provide a comparative analysis to determine the advantages of using natural gas foams relative to conventionally used slickwater, linear gel, and crosslinked fluid.
A full 3D reservoir model in a Duvernay Shale formation was constructed. Fundamental laboratory and pilot field tests data was collected for the NG foam fluid properties for numerical modeling. Rheology, friction, and leakoff properties of the fracturing fluids were incorporated in creating a numerical model. A 3D-complex hydraulic fracture simulation model incorporating 1D and 2D particle transport models were used. A numerical reservoir simulation for different sensitivity scenarios was incorporated for fracture modeling and gas production evaluation. Owing to lower density than conventional liquid column, the NG-foamed fluids are likely to result in higher surface pressure.
A reduced pump rate with NG foamed fracturing fluid leads to a lower frictional pressure loss in tubing, without compromising the ability to place the desired amount of proppant in the formation. The non-Newtonian shear-thinning NG-foamed fracturing fluid exhibits a higher, effective viscosity that enables effective transport of the proppant. Modeling results indicate that the overall fracture geometry and proppant placement is much better for NG-foamed fluids than high-volume slickwater needed to pump the same amount of proppant for well spacing and a field development plan. The simulated production performance for medium-viscosity fluids such as NG-foamed fluid, linear gel, and high-viscosity slickwater, is better than that of low-viscosity slickwater or high-viscosity crosslinked gel fluids. A low-viscosity fluid results in proppant settling and dunning, resulting in lower conductive height of fractures while the high viscosity treatment uses less fluid, so the surface area created is less and there is potential for height grow out of the target formation.