## 1 Introduction  
Hydraulic fracturing has become a well-known process to induce and propagate fractures in rock formations to extract unconventional natural gas, including shale gas. During this fracturing process, a pressurized fluid is injected through a wellbore to generate fractures in the rock formation to eventually improve the reservoir permeability, resulting in greater production rates [1; 2; 3]. The application of hydraulic fracturing for commercial shale gas production has been successful in the USA, and shale gas currently contributes about 17% of the total U.S. natural gas production [4]. The success of shale gas extraction through hydraulic fracturing in the USA has encouraged other countries, including Canada, China and Australia, to investigate the potential application of this technique for shale gas extraction. However, the key challenge in hydraulic fracturing is the selection of the most suitable working parameters, including the fracturing fluid, injection flow rate and number of fracturing stages, to obtain greater gas production. To maximize the production rate while minimizing the production cost, it is necessary to have a comprehensive knowledge of each phase of the hydraulic fracturing process, including breakdown pressure (the pressure at which the rock matrix fractures), extensiveness, size and width of the fracture network generated, the direction of the major fracture and corresponding permeability enhancement [5; 6]. For example, precise knowledge of breakdown pressure is required prior to deciding on the reservoir treatment parameters, because fracturing pressure should exceed the breakdown pressure to initiate fractures. Therefore, matrix stimulation treatments (to improve permeability by using acids, chemicals and solvents) are always conducted before reaching the breakdown pressure. Researchers have therefore attempted to investigate and quantify the parameters influencing the hydraulic fracturing process. According to past studies, some reservoir properties, including overburden stress, confining stress, mechanical properties, and the mineral composition of the rock formation, and injecting fluid properties, such as injection fluid type and flow rate, have been identified as governing parameters for hydraulic fracturing [7; 8; 9; 10]. In order to achieve efficient gas extraction using the hydraulic fracturing process, two main conditions must be met: (1) the selected reservoir should be hydraulically fractured to produce a broad fracture network that is well interconnected; and (2) the generated fracture network should have the ability to improve the reservoir's permeability to enable the extraction of a sufficient amount of gas from the reservoir. Both of the above criteria depend on the reservoir properties, especially the brittleness characteristics and stress conditions. Currently, hydraulic fracturing and the associated permeability improvement are studied using both laboratory experiments [11; 12; 13; 14; 15] and numerical simulation [6; 16; 17; 18; 19]. Among the numerical studies, [PERSON] et al. [19], has developed a model based on the distinct element method to study the fracture initiation and breakdown pressure. However, in light of the associated high computational costs, meshing and re-meshing difficulties, difficulties in incorporating the heterogeneities and the anisotropy of the rock mass, and calibration of the models used in numerical modelling, laboratory experiments can play a vital role in the study of the hydraulic fracturing process in deep gas reservoirs, including shaley plays. For example, [PERSON] et al. [7] conducted fracturing experiments using 300 \(\times\) 300 \(\times\) 300 mm cement mortar blocks and found that the direction of the hydraulic fracture is always along the direction of the maximum principle stress, and the injection rate of the fracturing fluid has an obvious influence on the breakdown pressure (higher injection rates cause faster hydraulic fracture propagation).