The enhancements to the oil production process produced by high viscosity friction reducers (HVFRs) has increased dramatically. The HVFR fluid improves processes during hydraulic fracture operations and provides a successful reduction in friction compared to the traditional treatment, which employs linear gel such as guar. The research aims to determine proppant capability performance of HVFRs and linear gel by conducting intensive laboratory investigations. These investigations aim to elucidate the effects of rheological fluids and fracture geometry on the static and dynamic settling velocity of the proppant inside fractures using HVFRs compared to linear gel fluids. Various concentrations of HVFR and guar were used for both the rheology and the proppant test experiments. The rheology and settling measurements show greater improvement of HVFR to distribute the proppant in the fracture compared to guar. Interestingly, a lower concentration of the HVFR (i.e., 2 gpt) provided improved viscosity and elastic properties than the standard concentration of linear gel (i.e., 20 ppt). This work will contribute to a better comprehension of HVFRs' ability to transport proppant. Ultimately, this improved understanding can assist hydraulic fracturing companies to build better friction reducers.
The main objective of a hydraulic fracture is to improve the formation conductivity and, subsequently, increase the production rate of oil wells. To achieve this, the sand carried inside the fracture must be distributed throughout the entire fracture length, with a lower surface treating pressure (Shen et al., 2018; Dahlgren et al., 2018). A traditional treatment system (hybrid system) works well where there is a high network complexity. This system also provides a good sand transport, especially at lower sand loadings or smaller mesh sizes. However, such systems require more chemicals, meaning greater tank and truck footprints, and larger amounts of water required to transport the proppant deep into the fracture (Zhao et al., 2018; Van Domelen et al., 2017). Moreover, this type of system is poorly equipped to carry the sand ftirther into the fracture, especially with higher proppant loadings or larger sand sizes. This can cause screenout due to the concentrated sand bank near the wellbore, which would require increased pumping pressure. The combination of these limitations increases the total cost of hydraulic fractures (Shen et al., 2018; Aften and Wason, 2009).