**6.1 Water-blocking effect**

Inorganic clayey matrix is generally known to be water-wet therefore providing favourable conditions for imbibition of water from fracturing fluid within fractures. In this process, the invading water displaces gas from the surface of clay matrix which leads to the formation of a multiphase flow environment near the fracture surface (**Figure 2**). Development of this phenomenon can create an unfavourable saturation condition, under which gas flow through fractures is hindered, thus lowering yield for wells. The phenomenon is known as water-blocking and it is has been described by researchers as one of the most severe damages in reservoirs with ultra-low permeability [82–84].

Recent experimental works on the imbibition of water by shale rocks showed that the imbibed water remains within the pore network, thus reducing the permeability to gas of the reservoir [81]. Simulation and history matching also confirmed that invasion and wetting of clay mineral surfaces by water from fracturing fluid

#### **Figure 2.**

*Fracture and near-fracture clay-fluid interactions (adapted from [103]).*

was responsible for decline in gas production. Reduction in gas flow due to water blocking effect has also been reported by Shanley et al. [85], who observed drastic reduction in gas production when water concentrations in fractures exceeded 40–50%. Detailed study of water-blocking phenomenon has showed that this phenomenon may cause permanent damage for some shale formations whiles the damage is transient for other shale types [70, 71, 86]. The details of mechanisms and variables that determine whether damage is temporal or permanent are still being investigated.

### *6.1.1 Water-blocking effect as a transient effect*

Water-blocking during fracturing of unconventional reservoirs is explained by the presence of two pore types in unconventional formations. The first pore types are the larger oil-wet pores located within the organic matrix of the formation. The second type of pores are the smaller water-wet pores located within the inorganic argillitic matrix. Pore throats of the larger oil-wet pores are however small. During hydraulic fracturing, high pressure fluids break the formation to form fractures with some fracturing fluids leaking off into near-fracture matrix. Once in the matrix, the fluids first occupy the larger oil-wet pores. However, due to smaller pore throats, fracturing fluid in the formation is segmented within each internal pore with minimal linkage to other pores. This causes water to be domiciled in formation as droplets filling larger oil-wet pores which subsequently makes remobilisation difficult upon resumption of production. This phenomenon significantly reduces hydrocarbon effective permeability. The natural healing process in this phenomenon occurs when fluid is drawn from larger pores into smaller water-wet pores deeper within the reservoir thus dissipating the water blocking effect. This leads to improved permeability and hydrocarbon production [71].

#### **6.2 Mineral dissolution and precipitation**

Clay minerals and non-clay minerals (carbonates and quartz) within a formation are susceptible to geochemical attack from the fracturing fluids. Most shale formations were deposited in sea water-rich environments and have established equilibrium of their minerals and fluids over geological time. Once these formations are exposed to engineering fluids, especially water-based fluids, the

*Review of Geochemical and Geo-Mechanical Impact of Clay-Fluid Interactions Relevant… DOI: http://dx.doi.org/10.5772/intechopen.98881*

geochemical equilibrium is no longer stable. Subsurface temperature, pressure, and pH often enhance geochemical reactivity of scale-forming minerals, resulting in changed porosity, and fracture permeability as a result of mineral dissolution and precipitation [87, 88].

Dissolution of rock forming minerals has been reported at low pH. As pH increases, ions from dissolved minerals recrystallise to form new minerals and/or amorphous precipitate that may have an adverse effect on formation permeability. At very high pH, clay minerals within a formation become unstable and may become mobile. This situation leads to migration of illite samples which may occlude the hydrocarbon flow paths within the formation (**Figure 2**).
