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In this study, we conducted indoor temporary plugging and diverting fracturing (TPDF) experiments on samples of natural deep and shallow coal seams using a small-scale true triaxial fracturing simulation system. By integrating high-precision CT scanning technology and crack reconstruction techniques, and relying on the quantitative characterization of the crack complexity coefficient, we investigated the differences in internal structures between deep and shallow coal seam samples and the variations in the expansion of TPDF cracks. Furthermore, the study primarily focused on exploring the influence of temporary plugging agent (TPA) parameters (quantity and particle size) on the expansion patterns of TPDF cracks in deep coal seam coal-rock samples. The experimental results reveal that in shallow coal samples, artificially induced fractures are notably longer and extend to various surfaces of the samples. Conversely, in deep coal samples, the expansion of artificially induced fractures is influenced by well-developed cleavage and cleats. The crack complexity coefficient of artificial fractures in deep coal samples is 1.54 higher than that in shallow coal samples, with an increased crack width of 98 μm. However, the expansion distance of the fractures is shorter and does not extend to the S3 and S6 surfaces. Increasing the dosage of the TPA is advantageous for inducing frequent redirection of fractures and communication with previously untouched areas. When the dosage of the TPA is increased from 30 g/L to 60 g/L, the expansion distance of artificial fractures significantly increases, extending to various surfaces of the samples. The crack complexity coefficient increases by 1.1, and the crack width enlarges by 84 μm. Appropriate particle sizes of the TPA can effectively form seals. However, small particle sizes (200/400 mesh) struggle to seal initial fractures, while large particle sizes (10/20 mesh) can lead to excessive wellhead blockage, causing rapid shut-in pressure, destructive fracturing in deep coal samples, and the generation of a large amount of coal fines. This study holds significant guidance for the optimal selection of process parameters in the temporary plugging hydraulic fracturing of deep coal rock.

In order to meet the development needs of economic and efficient in oilfield distribution network,and to realize the goal of low carbon more quickly,the investment decision-making method of energy-saving measures optimization is proposed. Firstly,the loading behaviors of pumps is analyzed,an calculation model for special line loss of oilfield distribution network based on load superposition characteristics is proposed,which is corrected according to the actual load of oilfield. Next, according to different energy-saving models and the GM(1,1)gray prediction model,the optimization investment decision model of oilfield distribution network is established. Then,based on the characteristics of oilfield energy-saving measures,the direct comparison objective method and the taboo search method are respectively selected to solve the solution of the different oilfield scale. Finally,a 30-node 6 kV distribution network line in an oilfield is taken as an example for simulation verification. The results show that the energy-saving and loss reduction scheme of oilfield distribution network obtained by the investment decision-making method in this paper has high cost performance and can effectively improve the voltage at the end of the line.

Deep coalbed methane reservoirs generally exhibit characteristics such as extremely low permeability, significant heterogeneity, high in situ stress, and dense geological discontinuities. Notably, these geological discontinuities cleats, bedding planes, and natural fractures, as mechanically weak planes, significantly contribute to the creation of extremely complex and tortuous hydraulic fracture (HF) networks near the wellbore, but impede the propagation of HFs to the far-field region. This will lead to insufficient stimulated reservoir volume, thereby limiting the CBM production. Under this background, a series of physical simulation experiments of temporary plugging and diverting fracturing (TPDF) were carried out on large-size coal blocks under true triaxial stress conditions. Combining high-energy industrial computed tomography scanning technology, first, the morphology of fracture propagation of the sample before TPDF is divided into two fracture propagation modes. Then, TPDF experiments were conducted to analyze the behavior of fracture propagation under different modes. Finally, a mode of TPDF tailored for adjusting the HF network geometry in deep CBM reservoirs was explored innovatively. The effects of concentration and particle size of the temporary plugging agent (TPA) on pressure increment, plugging location and fracture diversion behavior during TPDF were examined in particular. Experimental results indicate that optimizing the concentration and particle-size of TPA based on the resulting fracture geometry is crucial for adjusting the fracture network geometry (simplifying the growth behavior of HF near the wellbore while increasing fracture complexity in the far-field region) during conventional fracturing (before using the TPA). When a complex fracture network is created under the condition of formation with high-dense natural fractures (NFs) near the wellbore region, using small-particle-size TPA (e.g., 70/140 mesh) is optimal for adjusting the fracture geometry, as it can effectively plug the NFs and allow them to continue extending toward the far-field region. Meanwhile, a higher concentration of TPA is beneficial for plugging the interval of HF closer to the wellbore, and then causing the creation of complex fracture networks. When a long single HF is generated under the condition of a formation with low-dense NFs, using the medium-particle-size TPA (e.g., 40/70 mesh) is optimal for enhancing the fracture complexity near the wellbore region. Using TPA of excessively large particle sizes (e.g., 20/40 mesh) tends to plug the HFs at their entrances, causing HFs to be reinitiated from the unstimulated segment of the wellbore. This study can provide crucial theoretical guidance for optimizing the scheme design of TPDF in deep CBM reservoirs. [ABSTRACT FROM AUTHOR]

In the Bonan block of the Jiyang Depression, the lacustrine shale exhibits various types of organic-rich laminar lithofacies with complex distributions in lamination density and thickness, showing clear cyclic variations vertically over scales of several meters or even centimeters. These variations in lamination density and depth significantly impact the effectiveness of fracturing treatments in well placement. This study utilized downhole cores from the Shahejie Formation in the Bonan block, and based on the development characteristics of the lamination, a sampling scheme was designed. Small-scale true triaxial hydraulic fracturing experiments were conducted in the laboratory, focusing on the relationship between lamination density and perforation locations. Post-experiment analyses using computed tomography and acoustic emission monitoring examined fracture morphology, width variations, and proppant migration and placement within the fractures. The results indicate that high lamination density influences the propagation path of hydraulic fractures, restricting their vertical penetration through layers. Fracture initiation points closer to the lamination result in lower fluid injection pressure rise rates, thereby reducing the efficiency of the fracturing fluid. Lamination activated at the same depth generally produces narrower fractures than the main hydraulic fractures. Proppants are predominantly distributed within the main hydraulic fractures, with limited vertical migration into the lamination, resulting in the propped volume accounting for less than 10% of the total fracture volume. This study provides new insights and optimization strategies for well placement and perforation positioning in the hydraulic fracturing of organic-rich laminar lithofacies shale reservoirs. [ABSTRACT FROM AUTHOR]

Exploring the adaptability of CO2 and water-based fracturing to shale oil reservoirs is important for efficiently developing shale oil reservoirs. This study conducted fracturing experiments and acoustic emission (AE) monitoring on the Jurassic continental shale. Based on high-precision computed tomography scanning technology, digital reconstruction analysis of fracture morphology was carried out to quantitatively evaluate the complexity of fractures and the stimulation reservoir volume (SRV). The results show that the fracturing ability of a single water-based fracturing fluid is limited. Low-viscosity fracturing fluid tends to activate thin layers and has limited fracture height. High-viscosity fracturing fluid tends to result in a wide and simple fracture. A combination injection of low-viscosity and high-viscosity water-based fracturing fluid can comprehensively utilize the advantages of low-viscosity and high-viscosity fracturing fluids, effectively improving the complexity of fractures. CO2 fracturing is adaptable to Jurassic shale. The breakdown pressure of the supercritical CO2 (SC-CO2) fracturing is low. Branch fractures form, and laminas activate during SC-CO2 fracturing due to its high diffusivity. Under high-temperature and high-pressure conditions, the aqueous solution formed by mixing CO2 with water can promote the formation of complex fractures. Compared with water-based fracturing fluid, the complexity of fractures and effective stimulation reservoir volume (ESRV) increased by 8.7% and 47.6%, respectively. There is a high correlation between SRV and ESRV, and the proportion of AE shear activity is also highly correlated with the complexity of fractures. The results are expected to provide better fracturing schemes and effectiveness for continental shale oil reservoirs. [ABSTRACT FROM AUTHOR]