## 4 Results and Discussion
### Effect of Confining and Injection Pressures on Intact and Fracture Permeability  
In addition to the breakdown pressure and fracture network, the flow characteristics of the reservoir and its alterations in the fracturing process and the influence of fracturing fluid pressure and reservoir properties such as depth are important for productivity enhancement by hydraulic fracturing. This was studied next, by observing the permeability changes with fracturing by determining the permeability of intact and fractured samples, and permeability variation with confinement and injection pressure. Permeability calculations were carried out based on the downstream flow rates. The observed effects of injection and confining pressures on the downstream N\({}_{2}\) flow rate of an intact silstone rock  
Figure 8: Fracture surface of (**a**) fractured sample at 1 MPa (this is the partially fractured sample mechanically split into two parts); and (**b**) fractured sample at 7 MPa confining pressure. Figure 7: Diagram of stresses and forces acting on the rock specimen. specimen at 7 MPa confining pressure, a fractured rock specimen at 7 MPa confining pressure, and a fractured rock specimen at 1 MPa confining pressure are shown in Figures 9-11, respectively. As the figures show, under all the test conditions the downstream flow rate increases with increasing time and gradually reaches a steady state. The steady state flow rate values were used to calculate the permeability using Equations (3) and (4). Figure 9: Downstream flow rate development with time for intact rock specimen, during permeability tests. (**a**) 5 MPa; (**b**) 10 MPa; (**c**) 15 MPa; (**d**) 20 MPa; and (**e**) 25 MPa confining pressure. Figure 10: Downstream flow rate development with time for hydraulically fractured rock specimen (at 7 MPa confining pressure), during permeability tests. (**a**) 5 MPa; (**b**) 10 MPa; (**c**) 15 MPa; (**d**) 20 MPa; and (**e**) 25 MPa confining pressures. According to Figures 9-11, the maximum flow rate for each condition increases with increasing injection pressure, regardless of confinement or fracture (intact or fractured). The effect of injection pressure on flow rate has been observed by many researchers for different reservoir rocks ([PERSON] et al. [34] and [PERSON] et al. [35] for sandstone samples, [PERSON] et al. [36] for geopolymer  
Figure 11: Downstream flow rate development with time for hydraulically fractured rock specimen (at 1 MPa confining pressure), during permeability tests. (**a**) 5 MPa; (**b**) 10 MPa; (**c**) 15 MPa; (**d**) 20 MPa; and (**e**) 25 MPa confining pressure. and [PERSON] et al. [37] for coal). This is because, when the injection pressure is high, the pressure gradient through the sample is also high, and this causes a higher advective flow from the downstream. Moreover, according to Figure 9e, at 25 MPa confining pressure, when the injection pressure is increased to 1, 2, 4, 6, 8 and 10 MPa, the time taken to achieve the maximum flow rate reduces to 510, 400, 330, 230, 210 and 120 s, respectively. This can be observed for all the confining pressures in the intact rock specimen (Figure 9). A similar trend was observed for all the confining pressures in the fractured sample that was fractured at 1 MPa confining pressure (Figure 11), and the time taken to achieve the maximum flow rate reduces to 200, 175, 125, 90 and 70 s when the injection pressure increases to 1, 2, 4, 6 and 8 MPa, respectively. However, for the 1 and 8 MPa injection pressures in the intact and 1 MPa fractured samples, this reduction is about 61 and 67%, respectively. Interestingly, this was not observed in the fractured sample that was fractured at 7 MPa confining pressure, and the time reduction to achieve maximum or steady flow rate with increasing injection pressure is negligible compared to the other two cases (the intact sample and the fractured sample at 1 MPa confining pressure).