**3. Fracturing fluids and fluid systems**

The crux of hydraulic fracturing is the injection of fluids to generate, within the formation, a pressure that is greater than the breakdown value. The breakdown pressure is fundamentally a function of the formation in situ stresses, the initial pore pressure and the rock tensile strength [105]. Several breakdown pressure models have been developed since the first and classical version derived by Hubbert and Willis [106]. Hubbert and Willis's model is built on the premise that fracture initiation and breakdown takes place when the hoop stress or minimum tangential compressive stress at the wall of the wellbore is equal to the rock tensile strength. The initiated fracture starts to grow when the fracture propagation pressure is attained. For solids-free (clean) injection fluids, the fracture propagation pressure is normally less than that required for fracture initiation [107]. The fracture propagation pressure is the pore pressure at the tip of the fracture. It is lower than the bottom-hole pressure, and this difference depends on permeability, injection rate, fracture length [108], and other factors such as the properties of the fracturing fluid. At times, the fracture propagation pressure is considered as the bottomhole treating pressure. In this case, its magnitude depends on the in situ stresses and the net drop in pressures [109]. The net pressure drop is influenced by the tortuosity between the wellbore and the fracture, and the viscous flows within the wellbore perforation tunnel and the propagating fracture. The characteristics of the fracturing fluid and fluid system are therefore important in hydraulic fracturing operations.

Some key parameters to consider when choosing or designing a fracturing fluid system include the fluid rheology, conductivity, compatibility between the reservoir rock and fluid, pressure drop along the fracture, environmental impact of the fluid constituents, costs, fluid viscosity and proppant transport ability, and friction losses (in the wellbore, perforations and fractures). The ideal fracturing fluid should be easy to produce; possess enough viscosity for proppant transport and shear resistance; minimise fluid losses, friction forces, and proppant and formation damage; be economically viable; and be compatible with the reservoir rock and in situ fluids [110]. Fracturing fluids can be classified as water-based, oil-based, foambased and acid-based.
