**6.3 Shale swelling**

Shale swelling during hydraulic fracturing results from swelling of clay minerals within fracture face and shale matrix (**Figure 2**). Three mechanisms have been noted to cause clay mineral swelling as water is adsorbed into nano-pores, micropores, meso-pores and even macro-pores of clay minerals in the formation. The first mechanism is swelling due to hydration of negatively charged clay surfaces with several water layers depending on the type of clay. This has been observed in various types of clays with different levels of water saturation [89, 90]. The second mode of swelling is similar to what causes imbibition of water into clay minerals, where the clay acts as a semi-permeable membrane. In this case water is moved into the inter-layer spaces of clay minerals causing massive swelling [91]. In the third mechanism, continuous expansion of clay interlayer leads to separation of the clay layers into different clay components thus transforming initially intact clay layers into inter-particle spaces [92, 93].

Swelling of clays within the fracture walls can lead to constricted apertures which severely restrict flow of hydrocarbons during production [94]. Clay swelling may also induce micro fractures in formations which may improve absolute permeability [95, 96].

#### **6.4 Stress development**

During fracturing, interactions between shale and invading fluids lead to swelling of clay minerals within the shale causing in-situ stress development. Osmosis has been suggested as the potential transport mechanism which causes swelling pressure build-up within shale rock. The reaction between clay minerals and invading fluid is observed to be a primary cause of damage to reservoir permeability during and after hydraulic fracturing. Previous experiments have shown that a chance of permeability impairment following fluid interaction with formation is directly related to the specific clay mineral content of the formation [31, 71, 97]. In the case that the solute concentration in fracturing fluid is significantly lower compared to concentrations in clay interlayer, osmotic swelling is likely to occur, where fluid is drawn into the interlayer with the aim of balancing the solute concentrations. This phenomenon leads to significant expansion of the clay minerals. Expansion of clay minerals therefore exerts pressure on surrounding pores and matrices thus leading to a build-up of stress.

#### **6.5 Mechanical weakening**

Geo-Materials mechanical properties are dictated by the amount of pore space present, compositional heterogeneities [98], solids (inorganic and organic) mechanical strength and the presence/absence of pore-fluids and

their composition. Therefore, mechanical weakening of formation rocks due to reaction with newly introduced fracturing fluids has been observed by a number of researchers. Akrad et al. [99] observed that sustained interaction between fracturing fluid and formation can induce softening of the formation rock thus reducing the Young's Modulus of the rock, therefore producing mechanical weakening. Du et al. [98] investigated mechanisms of fracture propagation due to hydraulic fluid injection and concluded that the mechanical response of formations due to interaction with fracturing fluid is directly linked to the mineral composition and geochemistry of rocks. In their studies of proppant embedment efficiency, Corapcioglu et al. [100] found that exposure of the formation to fracturing fluid leads to decrease in Young's Modulus of the rock. Research on the impact of fracturing fluid on formation mineralogical components has also showed that non-clay minerals (carbonates, quartz, feldspar and various sulfides/sulphates) as well as clay minerals, like chlorite, are susceptible to dissolution in fracturing fluids, leading to a reduction in the structural strength of the formation.

LaFollette and Carman [101] reacted Haynesville shale samples in fracturing fluid at temperature of about 300°F for periods of 30, 60, 120 and 240 days respectively and observed changes in Brinell Hardness of the samples. The highest reduction occurred between 60 to 120 days after which there was a marginal increase in hardness. Carman and Lant [102] also reacted rock samples with different fracturing fluids at temperatures close to subsurface formation temperatures. Their results showed that Brinell's Hardness for all the rock samples decreased after reacting with fracturing fluids.
