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Igneous rock oil and gas reservoirs have great development potential. Hydraulic fracturing is an important means for the development of these reservoirs. In the process of fracturing and increasing production, fracturing fluid is prone to a hydration reaction with clay minerals in igneous rock, and then, the structure and mechanical properties of t...
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Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology...
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... Undissolved macromolecules in the fracturing fluid (e.g., guar gum in the traditional fracturing fluid , or anionic (Guo and He, 2012), as shown in Fig. 3), contribute to solid phase damage. The adsorption and retention in the pore throat of the reservoir block the seepage channel and cause a decrease in rock permeability Zhang et al., 2022). Fig. 3(a) reveals that the original polymer solution characterized by a good three-dimensional network structure with a regular linear arrangement of molecular chains. ...
... Consequently, a significant portion of the fracturing fluid interacts with the subsurface reservoir, potentially leading to the softening of rock strength and influencing mechanical properties, including Young's modulus and Poisson's ratio. Zhang et al. (2022) noted that fluiderock interactions may result in a substantial decrease in rock strength, thereby enhancing proppant embedment and decreasing sand-packed fracture conductivity. Temperature and pressure are key factors in proppant diagenesis, a process that generally occurs at temperatures exceeding 150 C and can be expedited by elevated temperatures and stress conditions (LaFollette and Carman, 2010). ...
Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide. These reservoirs present unique challenges due to their deep burial depth (4500–8882 m), low matrix permeability, complex crustal stress conditions, high temperature and pressure (HTHP, 150–200 °C, 105–155 MPa), coupled with high salinity of formation water. Consequently, the costs associated with their exploitation and development are exceptionally high. In deep and ultra-deep reservoirs, hydraulic fracturing is commonly used to achieve high and stable production. During hydraulic fracturing, a substantial volume of fluid is injected into the reservoir. However, statistical analysis reveals that the flowback rate is typically less than 30%, leaving the majority of the fluid trapped within the reservoir. Therefore, hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved. The challenging “three-high” environment of a deep reservoir, characterized by high temperature, high pressure, and high salinity, exacerbates conventional forms of damage, including water sensitivity, retention of fracturing fluids, rock creep, and proppant breakage. In addition, specific damage mechanisms come into play, such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions. Presently, the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing, comprehending the underlying mechanisms, and selecting appropriate solutions. It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs, with limited attention given to deep reservoirs and a lack of systematic summaries. In light of this, our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs. Subsequently, we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs, taking into account the unique reservoir characteristics of high temperature, high pressure, and high in-situ stress. In addition, we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix, both artificial and natural fractures, and sand-packed fractures. We conclude by offering a summary of current research advancements and future directions, which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage.
... Fractures and small dissolved pores were the main areas where fracturing fluid stagnated. The guar gum fracturing fluid and slick water fracturing fluid were dominantly utilized in the unconventional reservoir fracturing, while the differences of formulations and properties of fracturing fluids would lead to a discrepancy in the microscopic damage of the reservoir [37]. Sun et al. [38] concluded that the cross-linked gel promoted the precipitation of carbonate minerals, whereas the slick water induced carbonate minerals to form the dissolute pores. ...
Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology was utilized to conduct high-pressure soaking tests on shale specimens treated with EM30+ + guar gum mixed water and CNI nano variable-viscosity slickwater, where various concentrations of a drag reducer were utilized. Additionally, the differences in porosity, permeability, mineral composition, and iron ion concentration before and after the measurements were compared, which were used to analyze the influence on the shale’s microscopic pore structure. It features a reduction in the total pore volume after the interaction with the fracturing fluid, with the pore-throat damage degree, porosity damage degree, and permeability damage degree ranging from 0.63% to 5.62%, 1.51% to 6.84%, and 4.17% to 19.61%, respectively. Notably, EM30+ + guar gum mixed water exhibits heightened adsorption retention, alkaline dissolution, and precipitation compared to CNI nano variable-viscosity slickwater, rendering it more deleterious to shale. Moreover, higher concentrations of drag reducers, such as EM30+ or CNI-B, predominantly result in damage to the shale’s micropores. Shale compositions characterized by lower content of quartz and elevated proportions of clay minerals and iron-bearing minerals showcase augmented mineral dissolution and precipitation, consequently intensifying the shale damage. The hydration expansion of mixed-layer illite/smectite profoundly diminishes the core permeability. Consequently, the mechanisms underpinning the damage inflicted on shale’s microscopic pore structure primarily involve fracturing fluid adsorption and retention, mineral dissolution, and precipitation, such as clay minerals and iron-containing minerals.
Hydraulic fracturing is a well stimulation technique involving the fracturing of bedrock formations by a pressurized liquid, in which proppants are added to keep the fracture open after the fracturing operation. The scale discrepancy between the rock specimen and the proppant may bring deviations in the analysis of proppant embedment depth if the fluid-deteriorated formation is treated as an isotropic medium. This study tries to uncover the origins of these deviations through numerical and analytical analyses. The fluid-deteriorated formation is first modeled as a layered rock to obtain equivalent elastic parameters under isotropic conditions. Then, the equivalent parameters are used in the numerical modeling of proppant embedment. The numerical simulations indicate that the simplification of the fluid-deteriorated formation into an isotropic rock results in an underestimation of the proppant embedment depth, and this deviation increases with the scale contrast between rock specimens and proppants. Hertz contact theory is utilized to explain this deviation. As a promising technique, the nano/micro-indentation is also proposed to depict the fluid-deterioration effect along the depth. This study provides methods for the calibration of mechanical parameters of fluid-deteriorated rocks in the analysis of proppant embedment.
While drilling into the igneous rock formations of the Shunbei area, problems such as loss of well circulation and borehole collapse occur frequently, seriously hindering the efficient development of oil and gas resources. Aiming to solve this problem, the physicochemical and mechanical properties of igneous rocks are studied through a series of laboratory tests to determine the main factors influencing formation collapse and instability. In addition to the laboratory results, the weak plane effect of fracture mechanics, the seepage effect of drilling fluid, and the hydration effect of the drilling fluid on the borehole wall stability of igneous rock formations are evaluated and analyzed by establishing a mathematical model. The results show that the microfractures in the igneous rock are relatively developed and can be divided into unfilled fractures and calcite-filled fractures. The mechanical strength of the matrix igneous rock is higher than that of the rock samples with microfractures. The compressive strength of calcite-filled and unfilled fracture samples is 1/3-1/4 that of matrix igneous rocks, and immersion in the drilling fluid has little influence on the mechanical strength of igneous rocks. The fracture weak plane effect has the greatest influence on wellbore stability. With the increase of the number of fractures at different angles, the collapse pressure equivalent density of the formation subject to the mechanical weak plane effect increases by 21% compared with that of the homogeneous formation without fractures. The seepage effect of the drilling fluid on borehole stability is secondary, and the equivalent density of the formation collapse pressure increases by 11%. Because of the low content of clay minerals, the hydration effect of the drilling fluid on borehole stability was minimal and the equivalent density of collapse pressure increased by only 2%. During the drilling process, considering the weak plane effect of the microfractures and the seepage effect of the drilling fluid, the drilling fluid density should be controlled at about 1.82 g/cm3. The effective plugging ability and rheological properties of the drilling fluid should be improved for the formation with microfractures. The research results can provide a theoretical basis for the safe and efficient development of igneous reservoirs.
