Hydraulic fracturing with slickwater is a field‐proven stimulation technology used in tight reservoirs. Because of the high pumping rate associated with slickwater fracturing, drag reduction (DR) is critical in minimizing pressure drop and the success of oilfield operations. In this paper, a new type of drag reducer (SPR) was synthesized with acrylamide and 12‐allyloxydodecyl acid sodium, and its drag reduction performance was evaluated. The results showed that the new drag reducer features low molecular weight, fast‐dissolving rate and low interfacial tension. The algorithm of estimating the drag reduction rate of non‐Newtonian fluid SPR was proposed and validated. Empirical or semianalytical models for estimating the friction ratio (σ) or friction factor (λ or f) were used to simulate the turbulence behavior of the SPR drag reducer under different Reynolds numbers (Re). The modified Virk's correlation could accurately model the turbulent behavior of the SPR drag reducer. A unified calculation formula was established in this study for different pipe diameters.

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures.

CO₂ foam fracturing in tight and shale reservoirs is a revolutionary technique for commercially viable production. Nevertheless, the screening of foaming agents used in CO₂ foam fracturing fluid and the understanding of foaming mechanisms have not been sufficiently investigated. This study aimed to provide a comprehensive method for evaluating and selecting an optimized foaming agent for CO₂ foam fracturing fluid integrating macroscopic and microscopic approaches through laboratory experiments and molecular dynamics simulations. The relationship between the molecular structure of the foaming agent and its corresponding foaming effect was elucidated by taking the interaction between CO₂ and the foaming agent into account. Foam evaluation experiments indicated that the anionic surfactants exhibited superior foaming capacity and inferior stability compared to zwitterionic and non-ionic surfactants. The molecular dynamics simulation results demonstrated that the foaming mechanism of the CO₂ foaming agent relied on the equilibriums between CO₂-surfactant, CO₂-water, and surfactant–water interactions. At the same time, it was found that if the molecular structure of the surfactant contained functional groups that could produce hydrogen bonding with CO₂, the stability of the foaming effect improved to a certain extent, but the foaming volume was not obvious. The classic hydrophilic–lipophilic balance (HLB) theory was not applicable when screening the CO₂ foaming agents. It was found that the ionic surfactants with CO₂-philic groups and linear structures were suitable as the main foaming agents for CO₂ foam fracturing fluids, while non-ionic surfactants with significant steric hindrance were suitable as auxiliary foaming agents. This study provides valuable guidance for selecting cost-effective foaming agents on-site and adds to the understanding of the relationship between the molecular structure of foaming agents and their foaming effects.

Herein, a study of phosphate synthesis reactions with triethyl phosphate, phosphorous pentoxide and mixed alcohols is described. The synthesized phosphates are used as gelling agents in LPG fracturing fluids. By this study, a phosphate product with good performance has been obtain by screening different combination of alcohols and various reaction conditions including the ratios of reactants, reaction temperatures and reaction times. The LPG fracturing fluid prepared with the phosphate product we optimized maintains a viscosity of 200 mPa s for 1.5 h at 90 °C and 170 s⁻¹ shear rate.

To address critical limitations of ultra-low viscosity supercritical CO₂ fracturing fluids, including excessive fluid loss and inadequate proppant transport capacity, a series of thickeners designed to significantly enhance CO₂ viscosity were synthesized. Initially, FT-IR and ¹H NMR characterization confirmed successful chemical reactions and incorporation of both solvation-enhancing and -thickening functional groups. Subsequently, dissolution and thickening performance were evaluated using a custom-designed high-pressure vessel featuring visual observation capability, in-line viscosity monitoring, and high-temperature operation. All thickener systems exhibited excellent solubility, with 5 wt% loading elevating CO₂ viscosity to 3.68 mPa·s. Ultimately, molecular simulations performed in Materials Studio elucidated the mechanistic basis, electrostatic potential (ESP) mapping, cohesive energy density analysis, intermolecular interaction energy, and radial distribution function comparisons. These computational approaches revealed dissolution and thickening mechanisms of polymeric thickeners in CO₂.