Temporary plugging technology is an important drilling technique for maintaining wellbore stability and resolving lost circulation problems. The key to its success lies in the use of materials that can form a tight and stable “temporary plugging layer” with certain pressure bearing capacity and a permeability close to zero in the loss channel near the wellbore. Experimental studies have been conducted to develop adhesion formulations for optimal temporary plugging materials, as the matching relationship between particle size and fracture width is critical [(0.5−1)/1]. By measuring the permeability of the temporary plugging layer under varying confining pressure with a soap foam flowmeter, researchers have been able to evaluate the effectiveness, degradation, and dosages of temporary plugging agents. It has been shown that a single-particle material, such as a walnut shell, has a smaller permeability than a hyperfine CaCO₃ coated temporary plug layer. The latter, however, is less capable of bearing pressure. By combining different materials, such as walnut shells and hyperfine CaCO₃ particles, the researchers were able to create a temporary plug layer that had the lowest permeability and did not change much at variable confining pressures. Its pressure-bearing capacity is strong and the temporary plug works well. Experiments have shown that a ratio of 2:1–3:1 of hyperfine CaCO₃ and walnut shell particles work well for plugging a fracture system with particles of size 2–3 times the fracture width. It developed an evaluation method for temporary plugging agents, studied their plugging capability and degradation performance for reservoir conversion, and evaluated degradation performance after successful temporary plugging. The temporary plugging rate of the temporary plugging agent increased from 98.10% to 99.81%, and the maximum temporary plugging pressure is 50.39 MPa, which can be completely reduced at 150°C for 4 h, meeting the technical requirements of “dense temporary plugging, two-way pressure bearing” to some extent.

Coalbed methane reservoirs exhibit a low strength and high heterogeneity, rendering them susceptible to coal fines generation during hydraulic fracturing operations. The detrimental impact of coal fines on the conductivity of the propped fracture has been overlooked, leading to a substantial negative effect on the later-stage recovery of coalbed methane reservoirs. Moreover, the particle size distribution of the composite proppant also affects the conductivity of the propped fracture. To mitigate the damage caused by coal fines to the conductivity of the proppant pack in CBM reservoirs, this study conducted conductivity tests on actual coal rock fractures. The aim was to assess the effect of various particle size ratios in composite proppant blends on the conductivity of complex fractures in CBM reservoirs. The ultimate goal was to identify an optimized proppant blending approach that is suitable for hydraulic fracturing in coal seams. The results indicated that, in terms of the short-term conductivity of coalbed methane reservoirs, the conductivity of composite proppants is primarily influenced by the proportion of large or small particles. A higher proportion of large particles corresponds to a stronger conductivity (e.g., the conductivity is highest at a particle ratio of 5:1:1 for large, medium, and small particles). On the other hand, a higher proportion of small particles leads to a poorer conductivity (the conductivity is lowest when the particle ratio is 1:1:5). In the long-term conductivity of coalbed methane reservoirs, the fluid flushing of the fracture surfaces generates coal fines, and small particles can fill the gaps between larger particles, hindering the infiltration of coal fines. Therefore, it is important to control the particle size ratio of composite proppants, with a predominant proportion of larger particles. This approach can maintain long-term conductivity and prevent the excessive infiltration of coal fines, thereby avoiding fracture blockage (e.g., the conductivity is highest at a particle ratio of 5:1:5, followed by a ratio of 3:1:3). Furthermore, considering the influence of proppant placement methods and the support effect on near-wellbore opening fractures and far-end sliding fractures, segmented placement is utilized to fully fill the fractures for short-term conductivity, whereas mixed placement is employed for long-term conductivity to achieve a balance in particle gaps and hinder the infiltration of coal fines. The findings of this study contribute to the understanding of proppant selection and placement strategies for efficient hydraulic fracturing in coalbed methane reservoirs.

Shale gas exploratory development requires a huge water source for hydraulic fracturing, but the well sites are mainly located in hills, which limits the industrialization of shale gas development. The CO2 foaming fluid can meet the requirements of fracturing fluid in fracking and relieve pressure on water resources. The friction calculation of the CO2 foaming hydro-fracturing fluid in the conduit flow is key to the reliability of the overall fracture engineering, which affects the formation stimulation effect. The friction properties of CO₂ foaming hydro-fracturing fluids were investigated by conducting flow experiments in HTHP conditions, and the influence of pressure, temperature, foam mass, and flow rate on the friction properties was obtained. Mathematical models of frictional drag coefficients have been developed to predict the frictional force of CO2 foaming gel hydro-fracturing fluids in turbulent flows, which can be useful in evaluating the rating of CO2 foaming hydro-fracturing designs.