PSI - Issue 66

Amani J. Majeed et al. / Procedia Structural Integrity 66 (2024) 212–220 Author name / Structural Integrity Procedia 00 (2025) 000–000

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While the oil industry increasingly adopts environmentally friendly practices in oil production (Majeed, 2023), numerous studies have concentrated on reservoir fractures to enhance production levels. Fractures come in two distinct forms: natural and hydraulic fracture (Al-Mukhtar, 2017). It's widely recognized that many researchers have explored the hydraulic dynamics of fluids within reservoirs characterized by natural fractures (Al-Husseini and Abood, 2019; Majeed et al., 2023, 2021b, 2021a, 2020; Majeed and Al-Rbeawi, 2022). However, hydraulic fracturing, also known as "fracking," is a method utilized to enhance the productivity or injectivity index of a producing or injection well, respectively. This technique, which has been employed for 50 years, involves creating new or expanding existing cracks in the rock formation to extract oil and gas, commonly referred to as petroleum hydrocarbons. Hydrocarbons naturally flow into the drilled well in conventional formations via porous rock. However, in unconventional formations (low permeability formations), hydrocarbons are confined within rocks and fracturing occurs to facilitate their flow out of those rocks. Fracking includes the high-pressure injection of a mixture of water, sand, and chemicals into rock formations to create fractures that aid in gas or oil extraction. The specific composition of the fracking fluid varies based on the formation's characteristics. For instance, shale formations often need a higher sand concentration to preserve fracture integrity, while other formations might require extra chemicals to improve fluid viscosity and proppant transportability. After fracturing, the fluid is usually diluted for easier removal through flow back to the surface. Fracturing fluids come in various types like foam fluids, carbon dioxide, nitrogen gas, gelled oils, aqueous polymer solutions with or without cross-links, viscoelastic surfactant (VES) solutions, slick water, and emulsions. In recent literary works, specific polymers have been brought to attention due to their ability to maintain high viscosity and effectively carry substances. (Li et al., 2014) conducted experiments involving brine samples with high levels of dissolved solids and a temperature of 270°F. Their cross-linked polymer solution retained a viscosity of 100 cP for over an hour before gradually decreasing. Even at 250°F, the solution maintained a similar viscosity for more than 2 hours. Likewise, (Monreal et al., 2014) employed a cross-linked polymer system to evaluate the carrying capacity of a fluid system. They conducted their analysis at a lower temperature of 150°F while dealing with high salinity. The results indicated good stability of the solution for an hour and a half, with a viscosity of 150 cP. However, the efficacy of polymers as fracturing fluids has been called into question, as reported by (Willberg et al., 1997), discovered that as little as 29–41% of the polymer used in fracturing fluid was recovered during the flow-back period from the well. In a scholarly work by (Fang et al., 2014), the discussion has been delved into comparing the distances and lengths of fractures induced by water, slick water, and CO 2 . The unique attributes of CO 2 , such as its gas-like diffusibility, liquid-like solubility, low viscosity, and remarkably low surface tension, enable it to swiftly infiltrate micro-porous materials. The ease of attaining critical conditions with CO 2 in contrast to water and other conventional liquefiable gases renders supercritical CO 2 an appealing choice with vast potential. However, the researchers concluded that supercritical CO 2 , owing to its reduced viscosity, can extend fractures over greater distances, allowing it to permeate smaller rock fractures and establish connections between them. In contrast, slick water, with its higher viscosity, can widen fractures, thereby aiding in the deposition of proppants. Moreover, surfactants play a crucial role in hydraulic fracturing fluids for a variety of purposes. They are effective in reducing interfacial tension, which in turn decreases capillary pressure. In rock formations with low permeability, the retention of fluid in small pores is often a result of capillary pressure. By reducing this pressure, less reservoir pressure is needed to initiate the flowback of the fracturing fluid. Furthermore, surfactants can be combined with gases in significant proportions, typically ranging from 60 to 80%, to create foams. These foams produce high-viscosity fluids that are ideal for efficient proppant transportation, have minimal water content, and boast excellent fluid recovery due to the predominance of gas within the foam (Harris, 1988). Hydraulic fracturing encompasses a linked procedure that involves two main aspects. Firstly, it involves the deformation of the solid medium, where the width of the fracture is influenced by the fluid pressure. Secondly, it entails the flow of fluid within the fracture, which exhibits a nonlinear relationship with both fluid pressure and fracture width. Fracturing operations depend on understanding hydraulic fracture dimensions and propagation. Accurate prediction of fracture size requires knowledge of rock and fluid properties, as well as in-situ stress. Many fracture models have been developed to estimate dimensions based on pumping rate and time (Liu et al., 2022; Sampath et al., 2018; Wasantha and Konietzky, 2017).