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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.

Conglomerate reservoirs are usually formed in sag slope belts, which have the characteristics of near-source rapid deposition, rapid sedimentary facies change, and distinct reservoir heterogeneity. Therefore, it is difficult to carry out treatments of stimulation because of insufficient understanding of the propagation mechanism of the unique "gravel-bypassing" and "gravel-penetrating" characteristics of fracture morphologies in Mahu conglomerate reservoirs. In order to study the law of hydraulic fracture propagation in conglomerate reservoirs, based on Brazilian splitting test results for conglomerates with different gravel particle sizes and different cementation degrees, true tri-axial fracturing experiments conducted in the laboratory were performed to conduct experimental research on natural conglomerate outcrops and analyze the effects of gravel size, fracturing fluid viscosity, and pumping rate on hydraulic fracture propagation morphology. The results show that: (1) the gravel cementation strength of fracture pressure is higher and the pressure drops preferably after fracturing. The fracture is more inclined to "pass through the gravel" to propagate in large-particle-size gravel. The poor gravel cementation of fracture pressure is relatively low-level and the pressure after fracture drops slightly, and fractures tend to occur at the margin of gravel; (2) using slick water for fracturing tends to initiate and propagate fractures at multiple points on the wellbore, which is conducive to the formation of complex fracture networks and the improvement of volume stimulation effects. Guanidine-gum fracturing has a higher fracture-forming efficiency and higher net pressure; and (3) a low pumping rate will increase the interaction degree between fractures and gravel, and gravels will cause a change in fracture roughness, resulting in small local fracture widths. [ABSTRACT FROM AUTHOR]

Shale reservoirs contain a certain amount of clay minerals, which can hydrate through imbibition when in contact with various water-based fluids during drilling and completion. Shale hydration can lead to structural changes in the shale such as the expansion of bedding planes and propagation of microfractures, consequently affecting the initiation and propagation of hydraulic fractures. However, the effect of shale hydration under confining pressure on hydraulic fracture propagation and stimulation effect is still unclear. To this end, a novel experimental method integrating shale hydration and hydraulic fracturing was proposed based on the laboratory triaxial hydraulic fracturing simulation system. This method enables a more realistic simulation of shale hydration and hydraulic fracturing process happening in downhole conditions. The experimental results show that under simulated reservoir conditions, water imbibition increases over time with the imbibition rate reaching its peak within 24 h. The breakdown pressure, number of fractures, and complexity of fractures are positively correlated with imbibition time. The increase in fracture complexity could be attributed to the increase in the number of fractures. In contrast, imbibition pressure (injection pressure for imbibition) has little influence on water imbibition. For specimens under different imbibition pressure, the breakdown pressure and the number of fractures are close, and the complexity of fractures does not change prominently; all are T-shaped fractures. It is believed that the closure of microfractures under confining pressure caused by hydration is the main reason for the increase in breakdown pressure. Higher breakdown pressure means higher net pressure in the wellbore, which facilitates fracture initiation where the breakdown pressure is higher. Therefore, shale hydration is conducive to the initiation of multiple fractures, thus increasing the number and complexity of fractures. [ABSTRACT FROM AUTHOR]

Temporary plugging and diverting fracturing (TPDF) is widely used to improve the stimulation effectiveness in coal seam. To study the fracture propagation behavior during TPDF in coal formation, a series of laboratory hydraulic fracturing experiments were performed on natural coal samples. Based on the results of sample splitting and fracture reconstruction, the influences of horizontal stress difference and the size of temporary plugging agent (TPA) as well as the concentration of TPA on hydraulic fracture growth were analyzed. Experimental results show that TPDF is beneficial for improving the fracture complexity even under high stress difference of 8 MPa. When the TPA of small particle size (70/100 mesh) was applied, the primary fracture could not be fully blocked whereas increasing the particle size of TPA to 20/40 mesh tended to cause accumulation and bridging in the wellbore, resulting in an abnormally high fracturing pressure. TPA with particle size of 40/70 mesh tended to be a reasonable choice for the target formation, as it could form effective plugging in primary fractures and promote the generation of new fractures. Meanwhile, optimizing the concentration of TPA was also conducive to improving the plugging effectiveness. Effective temporary plugging can be achieved by using appropriate TPA of proper size and concentration, which varies with different treatment parameters and formations. Laboratory experiments are expected to provide guidance for the parameter optimization for TPDF in coal seam. [ABSTRACT FROM AUTHOR]

Abstract A novel laboratory simulation method for modeling multi-staged fracturing in a horizontal well was established based on a true tri-axial hydraulic fracturing simulation system. Using this method, the influences of net pressure in hydraulic fracture, stage spacing, perforation parameter, horizontal stress bias and well cementation quality on the propagation geometry of multiple fractures in a tight sandstone formation were studied in detail. The specimen splitting and analogy analysis of fracturing curve patterns reveals: Multiple fractures tend to merge under the condition of high horizontal stress bias and short stage spacing with pre-existing hydraulic fractures under critical closure situation, and the propagation of subsequent fractures is possibly suppressed because of high net pressure in pre-created fractures and asymmetric distribution of fracture width. And the subsequently created fractures are situated in the induced stress decreasing zone due to long stage spacing, leading to weak stress interference, and perforation with intense density and deep penetration facilitates the decrease of initiation fracture pressure. The deflection angle of subsequent fracture and horizontal stress variation tend to be amplified under low horizontal bias with constant net pressure in fractures. The longitudinal fracture is likely to be initiated at the interface of wellbore and concrete sample with poor cementation quality. The initiation fracture pressure of the different stages increases in turn, with the largest increase of 30%. Pressure quickly declines after initiation with low propagation pressure when the transverse hydraulic fracture is formed. The pressure reduces with fluctuation after the initiation of fracture when the fracture deflects, the extension pressure is high, and the fracture formed is tortuous and narrow. There is a violently fluctuant rise of pressure with multiple peak values when longitudinal fracture created, and it is hard to distinguish the features between the initiation stage and propagation stage. [ABSTRACT FROM AUTHOR]

• Innovative sand fracturing experiments were conducted on China's continental shale. • Various weak planes and mineral composition variations cause fracture complexity. • Most proppants deposit in main HFs, leaving opened laminas and branches unpropped. • Conductivities of different types of fractures created are significantly different. Continental shale oil formations generally exhibit more complex lithology and stronger heterogeneity than marine shale. The coexistence of dense laminas, lithologic interfaces (LIs), and mineral-filled natural fractures (NFs) in such formations can cause complex mechanisms of hydraulic fracture (HF) growth, proppant placement, and conductivity evolution. To obtain an intuitive understanding of this problem, a series of comprehensive laboratory sand fracturing experiments and fracturing conductivity tests were carried out innovatively on downhole shale cores using an improved small-size true triaxial fracturing simulation system combined with multiple examination methods in this work. HF morphology and proppant distribution were characterized through the high-precision CT scanning technique. Moreover, HF conductivity was tested on the cylindrical cores drilled from the fractured specimens. Experimental results show that high breakdown pressure and volatile wellbore pressure during the sand-adding stage were likely presented in the relatively rigid formations. HF growth path is likely to be deflected and bifurcated by the NFs laterally and by the oblique laminas vertically. "╪"-shaped HF also tends to be created due to the interaction of HF with dense horizontal laminas. The local heterogeneity in the continental shale formation can cause significant complexity and uncertainty in HF. The dominant HF nearby the wellbore contains most of the proppant, and the activated laminas, NFs, or/and branches are short of proppant. The volume and area of the proppant-filled HF can only account for less than 20% of the total HF volume and less than 65% of the total HF area, respectively. The distribution of relatively small-size proppant is more uniform and broader than that of large ones. There is a positive correlation between fracture conductivity and the proppant concentration. The conductivity of no proppant-filled fractures (including the HF, activated lamina, and NF) is low and unstable, and can almost be neglected under closure stress beyond approximately 20–25 MPa. The findings in this work are expected to provide practitioners with a bigger map of the performance and effectiveness of the hydraulic fracture they created. [ABSTRACT FROM AUTHOR]

On the basis of damage mechanics, a 2D fracture propagation model for seepage-stress-damage coupling in multi-fracture shales was established. Numerical simulations of hydraulic fracture propagation in the presence of natural fractures were carried out, with the use of mechanical parameters of shale reservoirs. The results showed that when hydraulic fractures encountered natural fractures in a shale reservoir, the morphology of fracture propagation was jointly affected by the properties of natural fractures (permeability and mechanical properties of rocks), approaching angle, horizontal stress difference, and flow rate of fracturing fluids. At a small horizontal stress difference, or low approaching angle, or small friction coefficient, natural fractures had increased potential to be damaged due to shear and tension. In such cases, the hydraulic fractures tended to propagate along the natural fractures. As the flow rate of fracturing fluid increased and the width of hydraulic fractures expanded, branch fractures formed easily when the net pressure exceeded the sum of horizontal stress difference and tensile strength of the rocks in which natural fractures with approaching angle smaller than 60° existed. It is seen, a high flow rate will increase the complexity of fracture network. However, when a large number of natural fractures with approaching angles greater than 60° existed, a large flow rate generally led to propagation of hydraulic fractures beyond natural fractures, which was not favored. Hence, an appropriate flow rate should be selected based on the orientations of natural fractures and hydraulic fractures. At the early stage of hydraulic fracturing, a low flow rate was favorable for the initiation of natural fractures and the growth of complexity of regional fractures near the well. Later, a higher flow rate facilitated a further propagation of hydraulic fractures into the depth of reservoir, thus forming a network of fractures. The underlying control mechanism of flow rate and net pressure on the formation of fracture network still requires clarification. The bending degree of the fracture propagation path depended on the ratio of net pressure to stress difference at a distant point as well as on the spacing between fractures. When the horizontal stress difference (<9 MPa) or coefficient of horizontal stress difference (<0.25) was low, the ratio of net pressure to stress difference was high. In this case, the fracture-induced stress obtained an enhanced significance, while the interactions of hydraulic fractures intensified, leading to a non-planar propagation of fractures. In addition, a smaller spacing between fractures caused intensified interactions of hydraulic fractures, so the propagation path altered more easily. This work contributes to the prediction of morphology of fracture propagation in unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]