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Hydraulic fracturing promotes the shale gas revolution worldwide. Since most of the fracturing fluids used now are water-based, shale hydration could happen before and after the treatment. However, the effects of shale hydration on hydraulic fracture initiation, fracture complexity, and proppant distribution have not been clarified. Thus, we performed shale hydration experiments on thin discs and cubic specimens under confining conditions to investigate the microstructure evolution through the scanning electron microscope (SEM) and acoustic emission (AE) system. Later, the hydrated cubic specimens were fractured to examine the impact of shale hydration on hydraulic fracturing through CT scanning. The results show that under confining conditions, water imbibition volume increases with time, but the effect of the fluid pressure inside the perforation on shale hydration is limited. The SEM images show that the preexisting microfractures extend at the beginning but stop growing with width reduction in 6 h, which is indirectly evidenced by the AE. The confining pressure inhibits the preexisting microfractures from opening and further propagation, resulting in closure of the microfractures near the perforation and the water imbibition stagnating. Those findings obtained from hydration experiments are verified by the hydraulic fracturing experiments, which show that the breakdown pressure increases with shale hydration. Meanwhile, the CT scanning shows that the fractures initiated from the vertical perforation become more complex after hydration, which leads to the width reduction of individual fractures and, consequently, poor proppant distribution. Therefore, it is suggested to utilize the optimal hydration time when microfractures expand or use clay inhibitors to decrease the breakdown pressure and facilitate the proppant placement. Highlights: Imbibition time plays a key role in shale hydration, but the effect of fluid pressure is limited. Microfractures extend in the early stage of shale hydration and finally close due to confining pressure. Breakdown pressure increases in the hydrated shale after 6-h hydration under confining conditions (25–18–3 MPa). Due to stress condition differences, more complex near-wellbore fractures form in vertical perforations than in horizontal ones after hydration. Complexity of the near-wellbore fracture patterns cause poor proppant distribution for the hydrated specimens with a vertical perforation. [ABSTRACT FROM AUTHOR]

Reactivating oil and gas wells, increasing oil and gas production, and improving recovery provide more opportunities for energy supply especially in the extraction of unconventional oil and gas reservoirs. Due to changes caused by well completion and production in pore pressure around oil and gas wells, subsequently leading to changes in ground stress, and the presence of natural and induced fractures in the reservoir, the process of refracturing is highly complex. This complexity is particularly pronounced in shale oil reservoirs with developed weak layer structures. Through true triaxial hydraulic fracturing experiments on Jimsar shale and utilizing micro-CT to characterize fractures, this study investigates the mechanisms and patterns of refracturing. The research indicates: (1) natural fractures and the stress states in the rock are the primary influencing factors in the fracture propagation. Because natural fractures are widely developed in Jimsar shale, natural fractures are the main influencing factors of hydraulic fracturing, especially in refracturing, the existing fractures have a greater impact on the propagation of secondary fracturing fractures. (2) Successful sealing of existing fractures using temporary blocking agents is crucial for initiating new fractures in refracturing. Traditional methods of plugging the seam at the root of existing fractures are ineffective, whereas extensive injection of blocking agents, forming large "sheet-like" blocking bodies in old fractures, yields better sealing effects, promoting the initiation of new fractures. (3) Moderately increasing the pumping rate and viscosity of fracturing fluid is advantageous in forming "sheet-like" temporary blocking bodies, enhancing the complexity of the network of new fractures in refracturing. (4) When there is a high horizontal stress difference, after sealing old fractures, the secondary hydraulic fractures initiate parallel to and extend from the old fractures. In cases of low horizontal stress difference, the complexity of secondary hydraulic fractures increases. When the horizontal stress changes direction, the secondary hydraulic fractures also change direction. It is recommended to use high-viscosity fracturing fluid and moderately increase the pumping rate, injecting blocking agents to seal old fractures, thereby enhancing the complexity of the network of refracturing. These findings provide important technical guidance for improving the efficiency of shale oil reservoir development. [ABSTRACT FROM AUTHOR]

The matrix permeability of shale reservoirs is extremely low. Therefore, massive volume fracturing is needed to form a complex crack network and get adequate sufficient capacity during the well completion. After fracturing, the effective stimulated reservoir volume (ESRV) is vital for developing shale reservoirs, mainly determined by stimulated reservoir volume (SRV) and the increase in permeability. Microseismic monitoring is widely used in the field to describe the crack shape and determine the SRV, to evaluate the stimulation effect. However, no studies have been conducted on the relationship between microseismic parameters and permeability. Thereby, we conducted uniaxial compression tests on Longmaxi shale samples and measured their changes in porosity and permeability before and after loading combining the microseismic monitoring under a laboratory scale (acoustic emission (AE)). Results show that porosity has little influence on the permeability before and after loading, while the propagation and connection of cracks are the most critical factors. As the loading stress increases, the crack volume and sample connectivity both grow. Besides, for the Longmaxi shale, when the stress is loaded to 30~50% of uniaxial compressive strength (UCS), the cracks start to propagate steadily (dilation), the permeability begins to increase rapidly, and percolation occurs, which indicates that the dilation point is closely related to the percolation threshold. The AE rate and accumulative ringing number both increase when it is larger than the percolation threshold value. The variation of AE characteristics can be used to identify the percolation threshold. Finally, the graphic model including AE parameters, crack, and permeability evolution is established based on the experimental results, which could help us understand the relationship between microseismic parameters and permeability and provide a methodological basis for the ESRV evaluation in the field. [ABSTRACT FROM AUTHOR]

Shale gas reservoirs contain a large number of natural fractures. When shear slip occurs during hydraulic fracturing, it will increase reservoir permeability and improve the reservoir stimulation performance. Because shale contains a large amount of clay and organic matter, its shear slip behavior differs from that of other rocks. In this study, the shear behavior of different shale blocks is experimentally studied, and the proportion of clay and organic matter in the shale dominates the shear slip behavior. Specifically, the friction coefficient and shear strength decrease with the increasing content of clay and organic matter. A microscopic support model was developed to describe the different shear slip behaviors for different contents of clay and organic matter. When the clay and organic matter content is lower than a critical threshold (~35%), shale is microscopically grain supported and brittle shear occurs and the material is prone to shear dilation. When this content is greater than a critical content (~43%), the microscopic structure is a matrix‐supported fabric and plastic shear occurs, which is prone to shear contraction. Shale with contents between these two critical thresholds has a mixed‐support fabric, which is a transition type between brittle and plastic shear. If the proportion of clay and organic matter is less than ~35%, the natural fracture tends to dilate and retain a certain degree of opening after shearing, improving stimulation performance. When the proportion is more than ~43%, shear contraction occurs on the natural fracture surface, which is not conductive and cannot increase reservoir permeability. Key Points: Friction coefficient and shear strength decrease with increasing proportion of clay and organic matterDeveloped microscopic support model to describe different shear slip behaviors for different proportions of clay and organic matterLower clay content is easy to dilate after shear slip, thus improving reservoir permeability [ABSTRACT FROM AUTHOR]

The development of gas shale needs a large scale of hydraulic fracturing during the process of well completion. However, the rate of flow-back is always less than the half of the injected fluid. Thus, a large number of fracturing fluid becomes retention in the shale reservoir and aqueous phase trapping (APT) appears. APT appears after well drilling, completion, work over and stimulation operation, caused by fluid filtrating into formation and resulting in permeability reduction. However, after the well was shut in for a period of time in shale gas development, the APT can be auto-removed. In order to investigate the auto-removal mechanism of shale reservoirs, related experiments were performed. In this paper, we used pulse-decay permeability method to monitor the permeability change of shale rocks during the process of shale rocks spontaneous imbibition. At the same time, the sandstones and volcanic rocks did as control samples. From the experiments, the permeability of sandstones and volcanic rocks decreases with increasing imbibition time, and there are no cracks produced in the process of imbibition of these two kinds of samples. However, during the process of shale rocks imbibition, cracks appear on the surface of samples, which may be caused by clay swelling. Simultaneously, the permeability of shale rocks fluctuates apparently. Some shale samples even have the specific interval that the permeability increases with soaking liquid time. This specific phenomenon may be caused by the new produced cracks, which increases the pore volume. Because the matrix of shale has the characteristic of hydrophobicity, much of the new pores couldn't be occupied by the liquid under the effect of spontaneous imbibition. Thus, the gas flowing channels tremendously increase. However, the stress sensitivity can lead to shale permeability decrease, which impacts the variation of permeability under certain confining pressure. These findings contribute to better understanding the shale APT auto-removal after hydraulic fracturing. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has become a necessary practice in order to obtain economical gas flow rates from gas shale. During and immediately following the creation of a fracture, high injection pressures cause fracturing fluid to leak off into the adjacent matrix, which leads to aqueous phase trapping (APT). However, after the well shut-in for a period of time, the APT can be auto-removed. The experiments of spontaneous imbibition and APT auto-removal combined with the low-field nuclear magnetic resonance (NMR) were performed to investigate the mechanism of the APT auto-removal of shale reservoir. Results show that new pores were not produced in the process of spontaneous imbibition in the tight sandstones and volcanic rocks, and with increasing spontaneous imbibition time, the fluid mass increased uniformly in the whole range of the pores. However, new pores were produced in shale samples in the process of spontaneous imbibition and through observing the process of experiments, the microcracks on the sample surface increased gradually, so we can make sure that new pores are mainly for microcracks. After sandstone had stopped soaking water, the liquid in the pore network wholly remained in the same place, while volcanic rock had certain flowing behavior. However there was obvious movement of fluid in shale sample, due to the tremendous imbibition force caused by ultra-micropores in shale. Therefore, after large-scale hydraulic fracturing of shale reservoir, under the effect of capillary force and clay swelling, on one hand, the retention fluid migrated along the initial microfractures to produce new pores, as can be proved that the new pores is new microcracks, so the gas flowing channel is enlarged by the new microcracks; on the other hand, under the influence of the capillary force, the fluid in the largish pores moved to the ultra-micropores, which apparently increased the area of the main gas flowing channel. The action of the two aspects contributes to the auto-removal mechanism of the shale reservoir APT. [ABSTRACT FROM AUTHOR]

An effective evaluation on fracture network forming capacity is key to the whole process of shale gas exploration. At present, neither a clear standard nor a generally accepted evaluation method exist. In this study, a novel “Soundless Cracking Agent (SCA) fracturing evaluation method” was developed. The fractures were characterized quantitatively using fractal dimension of the trace on the core surface and areal density. Acoustic emission (AE) location was used for dynamic monitoring and analysis. The results show that the fractal dimension can be used for quantitative evaluation of complexity of fracture network. The higher the rock hardness, the smaller the fracture density after fracturing is; the higher the brittleness, the larger the fracture density after fracturing is. The development degree of natural fracture systems and sedimentary bedding is a key factor to control the propagating morphology of fractures. The number of AE events for sandstones with low clay content (<25%) is huge, and there are obvious take-off spots for cumulative curves and frequency distribution curves. The AE events for sandstones are distributed along the main fractures, with simple planar fractures clearly present after fracturing. But for shale, the number of AE events is less, with no obvious take-off spots, and AE events are scatteredly distributed. The higher the clay content and the lower the quartz content, the smaller the number of AE events is, and the smaller the frequency and the sound source amplitude are. For sandstone, the number of AE events decreased by about 75% due to the increase of clay content by 20%. The new method enables a comprehensive reflection of the characteristics of rock hardness, brittleness and natural fractures system. This work is valuable for the evaluation of hydraulic fracturing effects in unconventional oil and gas reservoirs in the future. [ABSTRACT FROM AUTHOR]

In recent years, supercritical carbon dioxide (SC–CO 2) has been attempted in hydraulic fracturing in shale reservoirs as a new type of fracturing tool to overcome the drawback of traditional water-based fluids. Because of the unique physical and chemical properties of SC-CO 2 , its fracturing mechanism is more complicated than traditional fluids and still unclear at present. In this paper, we hydraulically fracture a shale reservoir rock using SC-CO 2 and monitor the fracturing process using acoustic emission (AE) data. The results show the fractures stimulated by SC-CO 2 composite of both shear and tensile fractures. In the initiation stage, SC-CO 2 activates the natural fractures around the wellbore and induces shear fractures. In the propagation stage, SC-CO 2 permeates the fracture tips quickly, results in a dynamic propagation process, and generates plenty of tensile fractures. The phase change of CO 2 could be observed during the fracture propagation process, which is accompanied by a rapid pressure change and local stress shock formations in the fractures. Additionally, the experiments also demonstrate that the existence of bedding structures in shale could constrain the propagation of fractures, thus leading to a smaller volume of fracture network and limiting the complexity of the generated fractures. This research may help understand the fracturing mechanism of SC-CO 2 and shed light on the development of hydraulic fracturing technology in shale reservoirs. [ABSTRACT FROM AUTHOR]

Understanding hydraulic fractures generation and geometric properties are significant for optimizing hydraulic fracturing treatment design which improves the ultimate production from shale reservoirs. The propagation of the hydraulic fractures is influenced by bedding planes. Simple opening or tensile crack model is not enough to meet the hydraulic fractures generation process, and the fault slipping model which is regarding as the cause of the natural earthquake is also not compatible with the actual physical meaning of fracking induced fractures. Hydraulic fractures consist of not only the opening but also slippage. Acoustic emission monitoring combined with the true triaxial hydraulic experiment provides direct information about the propagation and the geometric parameters of fractures. Moment tensor of acoustic emission is related to the mechanical mechanics of fractures. In this paper, the moment tensor interpretation is based on the shear-tensile crack model, then the orientation and the opening width of the hydraulic fractures are calculated. Computerized tomography scanning figures of the samples give support to the interpretation process. The distributions of hydraulic fractures orientations are different in the two samples with different normal stress applied on the bedding plane. Higher normal stress on the bedding plane led to a more complex fracture orientation. And the opening widths of the fractures in the far area from the wellbore are smaller than the fractures nearby the wellbore. These two parameters quantify the fractures geometric properties and provide information for adjusting the next step of the fracturing process. The findings of this study can help for better understanding of hydraulic fractures generation in the bedding shale. Shear-tensile crack model is supported by actual physical models has good adaptability in explaining the hydraulic fracture propagation process. • This paper used the acoustic emission to invert the fracture mechanism. The findings of this study can help for better understanding of hydraulic fractures generation in the bedding shale. • Shear-tensile crack model is supported by actual physical models has good adaptability in explaining the hydraulic fracture propagation process. • New parameters based on shear-tensile fractures model which extracted in the fracturing monitoring can be used for adjusting the next step of the fracturing process. [ABSTRACT FROM AUTHOR]