Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid.

Summary: Hydraulic fracturing is an effective stimulation method to establish high-conductivity channels in tight reservoirs, and the effectiveness of man-made fractures largely depends on the proppant-carrying capacity of the fracturing fluids used. As a novel completion fluid, silica gel-based fracturing fluids have shown desirable stimulation effect in application cases, but a comprehensive evaluation of their proppant settling and transport behaviors in the laboratory remains lacking. In this paper, a silica gel-based fracturing fluid was prepared first, and then the rheological properties, including shear thinning, recovery behavior, and viscoelasticity of the fluid system, were measured. Afterward, the settling velocity of single-particle proppant and the settling rate of multiparticle proppant under various experimental conditions were investigated in the static fluid system; in addition, the dynamic proppant-carrying performance was evaluated using a visualized rough fracture model to study different factors on the dune distribution inside the fractures. Lastly, the proppant-carrying mechanism of silica gel-based fracturing fluid was revealed in three aspects. The rheological test result showed that the shear viscosity of silica gel-based fracturing fluid increased as the SiO2 concentration increased. Furthermore, all tested fluid samples exhibited an elastic modulus that is consistently greater than the viscous modulus, indicating that the silica gel-based fracturing fluid system has a dominant elastic response behavior. In the single-particle static settling test, there was a significant increase in the settling velocities as the particle diameter increased and as the temperature increased. Meanwhile, the settling rate of multiparticles showed a decreasing trend with the increase in mesh size, while the proppant settling rate gradually increased as the proppant concentration rose. The results of dynamic proppant-carrying experiments demonstrate that a higher pumping rate leads to an extended migration distance for proppant, resulting in formed sand dunes with reduced height within fractures. Conversely, an increase in proppant concentration and a reduction in mesh size tend to form higher sand dunes. The proppant-carrying mechanisms of the silica gel-based fracturing fluid relate to the self-polymerization and syneresis of silica gel, the noticeable elasticity characteristics, and the structural encapsulation effect formed between silica gel and proppant. A better understanding of the proppant settling and transport behaviors of silica gel-based fracturing fluid can be helpful in optimizing the hydraulic fracturing design and promoting field application.

The migration and sedimentation behavior of proppant in complex fractures plays a vital role in the formation of fractures with high conductivity. Most of the existing studies on proppant sedimentation and migration are based on a single vertical fracture model that propagates in the same direction. However, due to in situ stress and reservoir heterogeneity, the propagation of fractures in reservoirs will produce multiple branch fractures that intersect with the main fractures and have a certain inclination angle. Therefore, it is necessary to study the sedimentation and migration behavior of proppants in inclined complex fractures. In this paper, the proppant particles sedimentation law in fractures is studied based on computational fluid dynamics. By changing the particle size, volume fraction, and inlet flow velocity of proppant, the migration and sedimentation law of proppant in a single fracture is simulated and verified. Then, through the establishment of a complex fracture model with multiple branches, and from the four dimensions of the vacant length of the front edge of the sand embankment, the length of the sand embankment, the highest point of the sand embankment, and the effective laying area of the proppant, the angle between the main and branch fractures in the complex fractures, the fracture angle and the inlet flow velocity, as well as the location relationship of the branch fracture setting and the migration and sedimentation of the proppant in the complex fractures are explored.

Solid phase residue, fracturing fluid filtration, and incomplete backflow during hydraulic fracturing can easily cause damage to tight sandstone reservoir. Thus, it is necessary to explore the relationship between the physical properties of tight reservoirs and damage caused by fracturing fluids. Based on the identification of reservoir physical properties, the relationship between reservoir physical properties and fracturing fluid damage was studied by core displacement, computerized tomography, and nuclear magnetic resonance (NMR). The results show that the higher the clay mineral content is, the denser the formed core is, and the corresponding core porosity and permeability are lower. When the permeability and porosity of the rock core are relatively high, the overall radius of the pore throat in the rock core shifts to the left under the action of the gel breaking fracturing fluid, showing a decreasing trend. However, when the permeability and porosity of the rock core are relatively low, the frequency peak of the smaller size of the pore throat in the rock core under the action of the gel breaking fracturing fluid increases upwards. The corresponding core permeability decline rate of the two types of tight sandstone reservoirs is 9.91%–8.78% and 15.85%–14.74%. The porosity decline rates are 5.53%–5.84% and 10.40%–9.94%. According to NMR results, it is speculated that under the action of gel breaking fracturing fluid, the small pore throats in the rock core are blocked or even disappear, while the proportion of smaller pore throats increases and the proportion of larger pore throats decreases. The results of this study provide theoretical reference for reservoir protection during the fracturing process of tight sandstone reservoirs.

A temporary plugging agent is an effective tool for increasing production in old wells. By considering the temporary plugging materials used in the remote WY area, three concentrations and five ratios under different fracture widths were designed and optimized. Thus, the fracture diversion under true triaxial stress was studied. The results showed that when the fracture widths were 2.0, 4.0, and 6.0 mm, the corresponding optimal plugging scheme was that the concentrations of the temporary plugging agent were 12.0, 18.0, and 18.0 kg/m³ and the ratios of 20–70 mesh to 200–300 mesh temporary plugging agent were 4:1, 2:1 and 4:1, respectively. When maintaining the same horizontal stress, an increase in the axial stress was accompanied by an increase in the fracture pressure; the initial fractures almost propagated along the direction of the horizontal maximum principal stress, but the shapes of the turning fractures were different. When the axial stress was the same, an increase in the horizontal stress difference was accompanied by a decrease in the corresponding fracture pressure and a gradual decrease in the degree of fracture turning. This study provides a basis for numerical simulation and field application of temporary plugging fracturing at fracture ends.

In coalbed methane reservoirs, intricate cleat fractures are well-developed and intertwine with artificial fractures. The uniform placement of fracturing proppants within these complex, interlaced cleat fractures is crucial for fracture conductivity and coalbed methane production. To investigate the impact of cleat characteristics and filling conditions in coal seams on proppant migration and placement, two fracture networks were established: one with full connectivity and another with a 50% fracture development degree. Utilizing computational fluid dynamics methods, we simulated proppant migration and settlement behavior in these two fracture network models under varying conditions, including fracturing fluid injection speed, sand-carrying fluid viscosity, and proppant particle size. We analyzed the mechanisms of these factors from three dimensions: the proportion of sand dome area, the balance height of the sand dome, and the horizontal distance from the entrance. The results indicate that: (1) Increasing the injection rate enhances the proppant's ability to migrate through multibranch fractures, and a higher injection rate can effectively fill the unconnected cleat fractures within a fracture network where the face cleats are 50% developed. When the sand filling ratio is consistent across different fracture network types, the network with 50% face cleat development requires a higher fracturing fluid injection rate. (2) Fracturing fluids with higher viscosity have stronger carrying capacity, effectively transporting proppant deeper into various fracture networks. (3) Smaller proppant particles exhibit better migration ability within the complex fracture network. When the proppant particle size is 0.25 mm, the overall sand filling ratio is similar in both development modes. Larger proppant particles can cause fracture plugging, particularly in coal seams with poor fracture development, where this plugging phenomenon is more pronounced. (4) Under the same fracturing fluid injection parameters, the overall sand filling ratio of the fully connected joint network is higher than that of the joint network with 50% developed face cleats. The migration of proppant in the fracture network with different development modes shows complexity and diversity, so it is necessary to formulate a suitable fracturing plan according to the degree of cleat development and construction conditions in the coal-rock reservoir.