**3. Fracturing fluids**

 The formation of fractures in reservoir rocks is initiated by fracturing fluid injection under high pressure to hydraulically break the rock, hence producing the stored hydrocarbons. Fracture treatment and fracturing fluid design are essentially dependent on the unique properties of reservoirs. Alteration of fracturing fluids is important in order to meet the targeted reservoir and operating conditions. Oilbased fracturing fluids were initially developed for fracturing job; however, due to the environmental and safety concerns, it was shifted to water-based fracturing fluids. An excessive amount of water utilization which can cause damage to watersensitive formations has led to the use of liquefied natural gas as an alternative. Besides the use of slickwater, chemical solutions for hydraulic fracturing have also been known as an effective technique for complex reservoirs which are naturally fractured, brittle, and tolerant of high water volume [20]. Other innovations such as water-based viscous polymeric fracturing fluids have been proposed, but they are still associated with some challenges, such as degradation of different molecular weight polymers and the formation of internal filter cake leading to undesirable damage to the reservoir rocks [20]. Slickwater which is mainly composed of water with a low concentration of chemical additives, or combination of different fracturing fluids has been commonly used for shale gas wells. As mentioned earlier, owing to different purposes of fracturing jobs, the utilization of other additives including acid, surfactant, potassium chloride, friction reduces, corrosion inhibitors, and pH adjusting agent at low concentration has been considered [21, 22].

### **3.1 Hydraulic fracturing fluids for shales**

 Shales have great variations with their typical characteristics that essentially determine the required hydraulic fracturing technique and fracturing fluid design. For shale fracturing jobs, fracturing fluid comprises of base fluid, additives, and proppant. Slickwater treatments using high injection rates and lower proppant concentrations have provided some advantages such as lower cost, reduced fracture height growth, and reduced gel damage within the fracture. However, the use of high volumes of fluids, poor proppant transport and suspendability, higher leakoff, and low fluid viscosity causing complex fracture geometries are disadvantages associated with slickwater usage as fracturing fluids [21]. Surfactant-based fluids were then proposed as fracturing fluid because surfactant molecules can undergo

self-association to generate micelles that can increase viscosity in the absence of polymer. Some modification of surfactant-based fluid system, such as nanoparticle addition, has been considered to stabilize the system at high temperature [23].

 Furthermore, single gas system has been reported to effectively increase the amount of energy required to recover the fluid and reduces water volume in shales that are classified as water-sensitive zones. However, there is a major disadvantage associated with the gas fracturing process which is the reduction in the amount of proppant that can be placed. The cost of operation also increases due to capturing, pressurizing, and transportation of the gas, for instance CO2. Additionally, separation of CO2 and CH4 during flow back would need additional facilities which will increase the expenses and the produced natural gas along with CO2 during the flow back period will also reduce. Supercritical CO2 has the ability to dissolve some amount of the water formed. When the amount of water reduces in order to achieve equilibrium with supercritical CO2, the remaining super saturated brine would cause salt precipitation which could block the flow channels and restrict the production [24].

 In water-sensitive reservoirs possessing high clay contents, fracturing fluid containing a small amount of water and large gas volume is preferred in order to reduce formation damage caused by high capillary pressure and permeability discontinuity as the impacts of clay swelling [25]. Foam also can reduce the damage around wellbore due to invaded fluid which eventually reduces the water volume used for hydraulic fracturing. Mixture of dispersed gas (N2 or CO2) and surfactant solution resulting in foam system has become another innovation whereby the foam can carry proppant efficiently with minimum residue left in the fracture. This system, i.e., N2 foam or CO2 foam, which is also known as energized fluid, has higher propagation ability into more complex fracture networks due to its mobility control ability. In other words, foam is able to carry proppant deeper in the formation in more efficient manner. CO2-based energized fluids have been reported to provide a better foaming performance leading to a higher recovery [26]. In ductile reservoirs, an efficient proppant placement is essentially required and fracturing techniques such as N2 foam and CO2 polymer have been implemented in ductile reservoir, e.g. Montney Shale in Canada [27]. CO2-based fluids can eliminate the need of water, provide extra energy due to gas expansion, and help in decreasing the flowback time.

 Recent developments of unconventional reservoirs including shale and tight gas and coalbed methane have put more emphasis on fracturing treatment with little use of water as the interaction between these reservoirs and the used fracturing fluids can negatively impact gas production [28]. The attempt to reduce water use in the fracturing process has been driven by several factors explained below in detail.

#### *3.1.1 Water-sensitive formations*

 The recovery of water, oil, and gas from unconventional reservoirs is essentially affected by the mineralogy of the rock formation. Ultra-tight formation with small propagated and natural fracture widths results in high capillary forces which are important for hydrocarbon production. The injection of water causes capillary barrier leading to production decline. In the case of water-sensitive formations having high clay content, clay swelling occurs during fracturing processes with waterbased fracturing fluid which can reduce formation permeability due to peeled pore surface and pore throat plugging. Changes in permeability due to clay swelling lead to capillary pressure and relative permeability shifts. These effects become more dominant when moving from micro to nano-Darcy permeability ranges [21, 29]. The excessive fine migration including clays in the near-wellbore region can also reduce the productivity. To avoid clay swelling and fine migration, different

fracturing treatments utilizing a little amount of water, such as oil-based fluids, high quality foams, and liquefied petroleum gas are preferred.
