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.

Summary: Fluid-flow fractures, through which fluids can move under pressure, make a more significant contribution to increasing production than do microseismic and propagation fractures. An accurate description of the distribution of fluid-flow fractures is the basis for evaluating hydraulic fracturing and oil/gas recovery. In this study, a real-time inversion approach for fluid-flow fractures was proposed, and the complex fluid-flow fracture morphology was obtained in real time by updating the data of the fracturing construction curve. First, a dynamic permeability model was proposed to describe the filtration rate of the fracturing fluid during hydraulic fracturing. Combined with the point source function, the flowing bottomhole pressure (pwf) can be quickly calculated based on the fracture morphology and displacement of the fracturing fluid. The variance of pwf and bottomhole pressure (pwb) obtained by pump pressure were used as an objective function, and the length of fluid-flow fractures and fracture morphology were used as fitting parameters. The length of the fluid-flow fractures was updated with the simultaneous perturbation stochastic approximation (SPSA) to achieve a rough fitting of the bottomhole pressure. On this basis, a probability function was used to constrain the randomness of the fractures, and the fracture morphology with a fixed fracture length was continuously simulated and finely matched. Finally, a complex fluid-flow fracture morphology was obtained. The method was used to analyze the fluid-flow fracture morphology of multifractured horizontal wells in shale reservoirs, and the fitting rate of the fracturing construction curve was more than 95%. The results show that the total length of the fluid-flow fractures in one stage in naturally fractured reservoirs was approximately 629 m, and those in homogeneous reservoirs and high-stress difference reservoirs were 564 m and 532 m, respectively. The length of fluid-flow fractures with “grooves” in the fracturing construction curve was longer than the length of fluid-flow fractures with “bulges.” The effectively stimulated reservoir area with fluid-flow fractures was only approximately 28–51% of the stimulated reservoir area with microseismic fractures.

During the underbalanced pressure drilling, the conical rubber core of the rotary blowout preventer((RBOP) is susceptible to alternating cyclic stress due to the alternating passage of the drill pipe body and its joint, which can easily lead to fatigue cracking and sealing failure. To improve the performance of the rubber core, the constitutive parameters of the rubber were obtained by fitting the uniaxial tension and compression test results with the Yeoh constitutive model. Subsequently, the finite element model of the dynamic sealing was established to simulate the sealing and stress law of the contact surface between the rubber core and the drill pipe. It can be concluded that the inner cylindrical surface of the rubber core is the main force bearing surface compared to other parts. The stress value is highest during the transition period when the drill pipe joint alternates with the drill pipe body. The stress amplitude of the sealing surface under the initial structure is 5.14 MPa, and the peak stress is 22.98 MPa. Then, Plackett-Burman (PB) design was used to screen out three structural parameters, which had significant effects on the sealing surface. Sensitivity analysis was conducted on significant factors to determine their effects on sealing stress. Combined with response surface design, the optimal combination of structural parameters was cone angle 27.7°, contraction angle 68.2°and inner diameter 82.1 mm. After optimization, the peak value of Mises stress was reduced by 3.64 MPa, the amplitude of Mises stress was reduced by 39%, and the prediction error was only 0.42 MPa, which verified the validity and accuracy of the response surface prediction model. This research can help effectively prolong the service life of the rubber core and reduce the risk of wellhead blowout.

The vertical expansion of fractures during hydraulic fracturing in low-permeability bottom-water oil and gas reservoirs is a crucial factor that significantly influences stimulation effectiveness. Fractures propagate concurrently in three dimensions; however, as operation time for fracturing and fracture length increase, there is a gradual reduction in fracture height. In the absence of a barrier layer or with inadequate strength and thickness, fractures may extend vertically or oscillate through it leading to an “unyielding” fractured state that impedes successful operations. This study introduces a mathematical model delineating the vertical expansion of hydraulic fractures (HFs) while computing stress intensity factors at upper and lower tips of each individual fracture. We use numerical methods to examine how vertical heterogeneity within reservoir rocks impacts laws governing vertical fracture propagation while conducting sensitivity analysis for making informed decisions on design parameters for hydraulic fracturing operations. The research results indicate that an escalation in stress disparity and increased toughness results in diminished height for HFs. Hydraulic fracturing augments fracture lengths along their respective axes. Nevertheless, if gap stress disparity surpasses net fluid pressure, a reduction in fracture length is observed. With an increasing ratio between local stress gradient versus fluid gravity gradient, HFs persistently advance vertically across cap and bed formations.