Viscous slickwater has a higher viscosity and better sand-carrying ability than conventional slickwater at the same concentration. At a concentration of 0.4 wt.%, the viscosity of the viscous slickwater is 4.7 times that of the conventional slickwater. It is generally believed that viscosity is one of the main influencing factors on the sand-carrying ability of the fluid. However, this study has shown that the good sand-carrying ability of the viscous slickwater is more attributed to its viscoelasticity. Through rheology and sand-carrying tests, it has been found that the viscoelastic properties vary when fluids have the same viscosity; this then leads to a significant difference in the settling rate of sand and the sand-carrying threshold of the fluid in a fracture at a certain flow rate. The routine method of characterizing the viscoelastic property of the slickwater was to observe the cross point of the elastic modulus (G′) and viscous modulus (G″) curves. The smaller the frequency of the cross point, the better the viscoelastic property of the fluid. However, it has been found in experiments that even when the cross point is the same, there is still a significant difference in the sand-carrying ability of fluids. Therefore, sand-carrying experiments are conducted under a similar cross point and different magnitudes of modulus, of which the results indicate that as the elastic modulus increases, the settling rate of sand decreases. The flow rate threshold occurring as sand settles obtained from laboratory experiments is compared with the field condition during hydraulic fracturing. From laboratory experiments, the threshold of inner-fracture flow rate that prevents the sand settling is found to be 8.02 m/min for 0.6 wt.% viscous slickwater with a sand ratio of 30%. In the field operation, the operation conditions meet the sand-carrying threshold obtained from laboratory experiments. Observations from the field test confirm the applicability of the threshold plot proposed according to laboratory measurements, which can provide guidance for optimizing the fracturing scheme in the field.

Effective proppant transport is critical to the success of hydraulic fracturing, particularly when using a non-Newtonian fluid. However, accurately predicting the proppant settling behavior under complex rheological conditions is still a significant challenge. This study proposes a new method for estimating the velocity of proppant settling in the power-law non-Newtonian fluid by accounting for spatial variations in viscosity within the fracture domain. The local shear rate field is first obtained using an analytical expression derived from the velocity gradient, and then used to approximate spatially varying viscosity based on the power-law rheological model. This allows the modification of Stokes’ law, which was initially developed for Newtonian fluid, to be used for the power-law non-Newtonian fluid. The results indicate that the model achieved high accuracy in the fracture center region, with an average relative error of 8.2%. The proposed approach bridges the gap between traditional settling models and the non-Newtonian behavior of the fracturing fluid, offering a practical and physically grounded framework for predicting the velocity of proppant settling within a hydraulic fracture. By considering the distribution of the shear rate and viscosity of the fracturing fluid, this method enables an accurate prediction of proppant settling velocity, which further provides theoretical support to the optimization of pumping schedules and operation parameters for hydraulic fracturing.

After fracturing with a guar fluid system in Chang 8 oil reservoir, some wells have high oil production, and some have low production and even only produce water. Therefore, a comparative study is carried out in oil-producing and water-producing wells. The results show that: ① Organic wax adsorbed in oil-producing and water-producing well core pores accounts for 95.39% and 56.67%, respectively, making wells strong oil-wet. A certain proportion of inorganic salts and some other oil-wet organic compounds exist in water-producing wells. ② Under the reservoir conditions, the oil wettability of the water-producing well core is strong, and its original formation wettability is also oil-wet. The original wettability of the oil-producing well formation is water-wet, with oil production capacity. ③ The core residual oil saturation using the guar fluid is 24.7%–29.87%. This results in no oil phase permeability or difficulty to mobilize oil in most oil reservoirs. ④ Forced displacement can mobilize oil in large pores and has a significant effect in producing well, with mobilization efficiency of 53.49%. This article elucidates the wettability formation and crude oil mobilization mechanism of two types of wells, providing direction for the development of this type of reservoir.