Different gel contents in a gel solution can create different viscosities, which is essential to simulate the actual fracturing fluid in the oil field. The flow of a viscous fluid always results in a pressure drop inof the fluid along the propagation path. However, the influence of this pressure drop seems small in laboratory scale. Thus, it is not necessary to apply a high flow rate. Taking low injection rate in the laboratory scale into consideration, highly viscous fluids and materials should be applied with low fracture toughness. Besides, regarding the conductivity of pre-existingpreexisting natural fracture in the sample, another scale factor is also considered for the stresses due to the dependence of fracture aperture on the average stress level. Therefore, in situ stresses simulation is a key point in the experiments ofon hydraulic fracturing. In the absence of discontinuity, tests are carried out at in situ stress, but when a pre-existingpreexisting natural fracture is introduced, the stress level should also be scaled with the pre-existingpreexisting natural fracture stiffness. The applied stress level is chosen to ensure an open discontinuity in the model block. In this way, fluid flow into pre-existingpreexisting natural fracture is the applied stresses which are much lower compared with the fracture pressure. Therefore, one should be careful in extrapolating the laboratory results to field conditions. More details on the scaling analysis as well as information about how to scale the testing variables can be found in Zhou (2008). During the fluid injection into the sample, wellbore pressure is increased until hydraulic fracture initiation and propagation are observed and when the injection pressure decreased gradually to a stable value, the fluid pumping is stopped.
It broke out again to propagate in a mechanically more favorable direction, depending primarily on the orientation of the natural fracture relative to stress.