Physical Simulation of Hydraulic Fracturing of Large-Sized Tight Sandstone Outcrops

Abstract

Summary Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.

3D experimental investigation on enhanced oil recovery by flue gas assisted steam assisted gravity drainage

“…With the continuous development of conventional oil reservoir resources, most common oil fields are entering into the exhaustion stage, water cut is relatively high, triggering that conventional oil and gas resources are difficult to maintain the current energy demand, therefore, more and more attention has been paid to non-conventional energy, such as heavy oil (Meyer et al, 2007), shale oil and tight oil resources developed by hydraulic fracturing technique Guo et al, 2021), furthermore, bioenergy including biodiesel produced by using catalysts has gradually become a key research object (Panchal et al, 2020;Panchal et al, 2021). The heavy oil resources are widely distributed in the world and have huge reserves that account for about 70% of the total oil reserves (Babadagli, 2018;Briggs et al, 1988).…”

A reservoir quality evaluation approach for tight sandstone reservoirs based on the gray correlation algorithm: A case study of the Chang 6 layer in the W area of the as oilfield, Ordos Basin

“…Reservoir quality evaluation is the basis of tight sandstone oil development. Due to the influence of sedimentation and diagenesis, tight sandstone reservoirs have poor physical properties (Guo et al, 2021), complex pore throat structures (Yang et al, 2020), strong reservoir heterogeneity (Ding et al, 2014;Dou et al, 2021;Kong et al, 2020;Lian et al, 2010;Liu et al, 2018), and small pore throat radii (Nelson, 2009). Detailed characterization of tight sandstone reservoirs is the key to unconventional oil and gas resource exploration and development (Cao et al, 2014).…”

Quantitative evaluation indexes of the spatial steering effect of directional perforation hydraulic fractures

“…The morphology of hydraulic fractures generated by directional perforation is the key to evaluating whether this technique has been successfully implemented. However, due to reservoir stress differences, mechanical properties of reservoir rock, wellbore radius, perforation parameters and injection pressure, hydraulic fractures deflect to different degrees after initiation at the perforation hole (Chen et al, 2017;Duan et al, 2021;Guo et al, 2020;Liu et al, 2021;Lu and He, 2020;Lu et al, 2020b;Lyu et al, 2020;Song et al, 2020). It is very important to quantitatively evaluate the influence of these factors on the fracturing effect of directional perforation hydraulic fracturing.…”