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Summary Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.

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Successful carbonate rock matrix acidizing should contribute to the formation of several main acid dissolution holes (wormholes), which provide favorable oil and gas seepage channels through the contaminated zone near the wellbore. The distribution and characteristics of wormholes play a critical role in deciding the acid penetration distance and acidification effect, while the development of wormholes is directly influenced by the acid fluid injection rate. In this study, carbonate rock cores are selected for displacement experiments, during which effects of different injection rates on wormhole development are compared. The breakthrough volume is a key parameter in determining the optimum acidizing fluid injection rate, while the pressure drop curve is used to analyze the development process of wormholes. Meanwhile, nuclear magnetic resonance imaging technology is employed to analyze the core end surface and internal structure after acidification to identify acid dissolution types and further determine the corresponding boundary of fluid injection rates for different acid dissolution types. The acid breakthrough volumes with different injection rates are calculated and compared when the hydrochloric acid concentration is 20%, which comes to the conclusion that the injection rate of 2 mL/min initiates the formation of wormholes and the injection rate of 3–4 mL/min results in the optimum acidification effect.

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