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Hydraulic fracturing by stimulated reservoir volume (SRV) is a necessity to realize commercial development of shale gas, and its stimulation mechanism still needs further study, and the effectiveness of supplementary stimulation measures needs further exploration. The shale always contains some carbonate minerals. This paper tests the permeability of acid-etched fracture in shale to explore the influence of carbonate mineral content, acid fluid types and concentration, fracture plane roughness, proppant, and confining pressure on the acid-etched effects in shale, and uses CT scanning to conduct research on variation of microscopic pore-throat texture in shale before and after acid-etching. The test shows that the roughness of the fracture plane perpendicular to the bedding plane is higher than the roughness of that paralleled to the bedding plane, and the roughness in both fracture planes perpendicular to and paralleled to the bedding plane increases as the carbonate minerals content increases. In same group of shale samples, the permeability of self-propped fracture before and after acid-etching respectively is positively correlated with the fractal dimension of the fracture plane before and after acid-etching, and the variation of permeability of self-propped fracture before and after acid-etching is also positively correlated with the variation of fractal dimension of fracture plane before and after acid-etching, which is not shown in different groups of shale samples. When the content of carbonate minerals in shale is between 10% and 30%, the relation between optimum HCL concentration and carbonate mineral content is expressed as Y (OptimumHCLconcentration) = −0.5X (Carbonatemineralcontent) + 0.15. If the shale has a high carbonate mineral content (>30%), the effect of acid-etching is not easily controlled, so the technique of acid fracturing should be carried out cautiously. The permeability of single-layer proppant and self-propped fracture after acid-etching conforms to Walsh theory within certain pressure, and variation and migration of curve slope reflects unstable arrangement, imbedding, and crush of proppant, and nonreactive filled impurity of clay and quartz desquamated and migrated, which coincides well with constant variation of permeability. Applying proper acid fluids and optimum concentration in shale with varying carbonate contents will increase pore size, fracture width, and fracture number. For the shale with abundant calcite-cemented fractures, the optimum acid fluid concentration should be increased properly. Due to ultralow permeability of the matrix in shale, even high concentration acid fluid could not penetrate the core with barren natural fractures or calcium-filled fractures. The results of research provide valuable information for design of acid fracturing in shale play.

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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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