Experimental Study of Plugging Agent Particle Size and Concentration on Temporary Plugging Fracturing in Shale Formation

Abstract

During the temporary plugging fracturing (TPF) process, the pressure response and pumping behavior significantly differ from those observed during conventional fracturing fluid pumping. Once the temporary plugging agent (TPA) forms a plug, subsequent fracture initiation and propagation become more intricate due to the influence of the TPA and early fractures. Factors such as concentration, particle size, and ratio of the TPA notably affect the effectiveness of TPF. This study employs a true triaxial hydraulic fracturing simulation system to conduct TPF experiments with varying particle size combinations and concentrations at both in-fracture and in-stage locations. The impact of different TPA parameters on the plugging effectiveness is assessed by analyzing the morphology of the induced fractures and the characteristics of pressure curves post experiment. Results indicate that combining dfferent particle sizes enhances plugging effectiveness, with a combination of smaller and larger particles exhibiting superior plugging effectiveness, resulting in a pressure increase of over 25.9%. As the concentration of the TPA increases, the plugging fracture pressure rises, accompanied by rapid pressure response and significant plugging effects, leading to more complex fracture morphology. For shale reservoirs, the density of bedding planes (BPs) influences the morphology and width of conventional hydraulic fractures, thereby affecting the effectiveness of subsequent refracturing. Rock samples with a relatively low BP density demonstrate effective plugging initiation both in-fracture and in-stage, facilitating the formation of complex fracture networks. Conversely, specimens with a relatively high BP density exhibit superior plugging effectiveness in-stage compared to in-fracture plugging.