## 4 Results and Discussion
### Effect of Confining and Injection Pressures on Intact and Fracture Permeability
For example, at 25 MPa confining pressure, when the injection pressure was increased to 1, 2, 4, 6 and 8 MPa, the time taken to achieve the maximum flow rate only slightly reduced to 40, 37, 35, 31 and 28 s. When compared with the 1 and 8 MPa injection pressures in the intact rock specimen, this reduction is about 92 and 87%, respectively. According to Figures 9-11 show that fractured samples require much less time to achieve the steady state or maximum flow rate compared to the intact sample, because of the presence of fractures in the hydraulically fractured samples. Moreover, in intact and fractured samples at 1 MPa confining pressure, the time lags between the 8 and 1 MPa injection pressures at 25 MPa confining pressure are about 300 and 130 s respectively. However, in the fractured sample at 7 MPa confining pressure the time lag between the 8 and 1 MPa injection pressures at 25 MPa confining pressure is only about 12 s. This is due to the existing rock matrix in the intact rock and fractured specimen at 1 MPa confining pressure, and the time to achieve the maximum flow rate is therefore dependent on the injection pressure. Moreover, flow through a rock matrix is governed by the properties of porous media, including pore size distribution and the interconnectivity of pores. In contrast, in the fractured sample at 7 MPa confining pressure, the time to achieve the maximum flow rate is independent of the injection pressure, and in this case the fracture is throughout the rock specimen. Therefore, the effect of the rock matrix is negligible, because the fluid flows through the generated fracture rather than through the rock matrix [38]. This is very useful in gas extraction, as when the fracture is large enough, the gas can be extracted at higher flow rates and the time to achieve the maximum flow rate is very short. This will directly reduce the maintenance and operating costs of the equipment and other accessories during gas extraction [39]. The effect of injection pressure and confining pressure on the N\({}_{2}\) permeability of intact and fractured siltstone permeability was then examined. Figure 12 shows these effects on the permeability of intact siltstone. According to Figure 12a, siltstone permeability first gradually (up to 6 MPa) and then slowly decreases with increasing injection pressure (up to 10 MPa) and eventually comes to a steady state (>10 MPa). For example, at 25 MPa confining pressure, when the injection pressure is increased from 1 to 6 MPa and 6 to 10 MPa, the permeability of the intact siltstone reduces by around 38% and 5%, respectively (Figure 12a). This clearly shows the significant influence of injection pressure on siltstone permeability at low injection pressures (<6 MPa) is greatly reduced at higher injection pressures (>6 MPa). This may be related to the Klinkenberg slip flow effect, which explains the difference between gas and liquid permeability in porous media using the \"slip flow\" phenomenon [40]. According to [PERSON] [40], the collisions between gas molecules and solid walls introduce an additional flux to the system when the pore radius is similar to the mean free path of the gas molecules. According to existing studies, gas permeability through various reservoir rocks can be reduced with increasing injection pressure due to this phenomenon [34; 41; 42; 43; 44]. This slip flow effect is therefore responsible for the observed gradual reduction in N\({}_{2}\) permeability from 1 to 6 MPa, and the observed negligible reduction in N\({}_{2}\) permeability after 6 MPa is possibly due to the increased advective flux effect caused by the reduced effective stress, which seems to reduce the slip flow effect. In relation to the confining pressure or reservoir depth effect on its intact permeability, according to Figure 12b, N\({}_{2}\) permeability in siltstone exhibits a reducing trend with increasing confining pressure, regardless of injection pressure.