Unconventional oil and gas reservoirs require a large-scaled fracturing to form dense and effective fracture network, so as to achieve the economic development. Slickwater (i.e., water with the friction reducer) has been widely applied in this field. However, it has low viscosity and poor sand-carrying performance, which increases the risk of sand plugging during fracturing. As for friction reducers, although increasing its concentration in water can slightly increase the viscosity of the slickwater, but this can dramatically decrease the friction reduction rate of the slickwater, which turns out to be detrimental to the stimulationnew. New viscous slickwater (i.e., water with the viscous friction reducer) was developed that can solve the above problems. It can meet the requirements of different viscosity by changing the concentration of the friction reducer (from 0.1wt% to 0.8wt%). With a simple operation process and lower friction reducer, it can effectively maintain a high friction reduction rate, and increase the efficiency of proppant carrying and fracturing fluid. In this study, through a series of laboratory experiments (including the rheological performance tests, friction reduction rate tests and sand-carrying tests), the friction reduction and sand-carrying performance of one chosen viscous slickwater were evaluated, and further compared with the conventional slickwater was conducted. Experimental results showed that a continuous viscosity change in a wide range could be achieved by controlling the concentration of the new viscous friction reducer. The viscous slick water with a concentration above 0.6 wt% could maintain the viscosity more than 50 mPa·s even with a high shear. While there was less different between the conventional slick water and the viscous slick water with the concentration of 0.1wt%, the viscosity of both was lower than 5 mPa·s. The friction reduction rate of the 0.1wt% slickwater could up to 77.5% with the flow rate in a pipe of 11 m/s. In the sand-carrying tests, no sand-settlement was observed. This allows sands to transport further into the hydraulic fractures and be uniformly distributed. The further tests were carried out in two horizontal wells in Jimsar shale oil reservoirs. Field data showed that the friction reduction rate was 81% in the fracturing, and the maximum daily oil production rate was 90 t/d, and the cumulative oil production was up to 4000 t/d in 80 days, which is 4 times of the production with the conventional fracturing fluid.

Surfactants are widely used in the fracturing fluid to enhance the imbibition and thus the oil recovery rate. However, current numerical models cannot capture the physics behind capillary imbibition during the wettability alteration by surfactants. Although the interacting capillary bundle (ICB) model shows potential in characterizing imbibition rates in different pores during wettability alteration, the existing ICB models neglect the influence of wettability and viscosity ratio on the imbibition behavior, making it difficult to accurately describe the oil–water imbibition behavior within the porous media. In this work, a new ICB mathematical model is established by introducing pressure balance without assuming the position of the leading front to comprehensively describe the imbibition behavior in a porous medium under different conditions, including gas–liquid spontaneous imbibition and oil–water imbibition. When the pore size distribution of a tight rock is known, this new model can predict the changes of water saturation during the displacement process in the tight rock, and also determine the imbibition rate in pores of different sizes. The water saturation profiles obtained from the new model are validated against the waterflooding simulation results from the CMG, while the imbibition rates calculated by the model are validated against the experimental observations of gas–liquid spontaneous imbibition. The good match above indicates the newly proposed model can show the water saturation profile at a macroscopic scale while capture the underlying physics of the multiphase flow in a porous medium at a microscopic scale. Simulation results obtained from this model indicate that both wettability and viscosity ratio can affect the sequence of fluid imbibition into pores of different sizes during the multiphase flow, where less-viscous wetting fluid is preferentially imbibed into larger pores while more-viscous wetting fluid tends to be imbibed into smaller pores. Furthermore, this model provides an avenue to calculate the imbibition rate in pores of different sizes during wettability alteration and capture the non-Darcy effect in micro- and nano-scale pores.