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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 propagation of multiple fractures plays a significant role in the effectiveness of hydraulic stimulation in shale oil reservoirs. Previous studies reported that the laminations and bedding interface in shale oil rocks could influence the propagation of single hydraulic fracture. However, the propagation mechanism of multiple fractures in such rocks is still unclear. Here we use a true-triaxial experimental system, together with the acoustic emission (AE) monitoring system, to investigate the propagation of multiple fractures in shale oil reservoir rocks. The results show that the fracture interference started at the initiation stage seriously affects the propagation of multiple fractures. More clusters per stage could aggravate the fracture interference near the wellhead. The laminations and bedding interfaces are the main causes of fracture interference and could hinder the height of hydraulic fractures. Shear-type AE event signals the generation of fracture interference caused by the slip of bedding interface and the deflection of fractures induced by the laminations. The mechanism of fracture interference not only lies in stress shadow but also in the changes in fluid pressure caused by the high permeability of laminations and bedding interface. The experimental results provide basic and detailed data for studying hydraulic fracturing in shale oil reservoirs. Highlights: True-triaxial experiment is conducted to investigate the propagation of multiple hydraulic fractures. Both the lamination and bedding interface influence multiple hydraulic fracture propagation. The AE monitoring indicates many shear-type fractures when fracture interference appears. [ABSTRACT FROM AUTHOR]

Conventional fracture closure models typically assume homogeneous formation. This assumption renders complex fracture closure pressure analysis during shut-in insufficient at present. In this paper, we use a cohesive zone method (CZM)-based finite element model to obtain the fracture closure pressure and minimum horizontal principal stress of the major fracture and the branch fracture based on pressure fall-off analysis. Key factors including leak-off rate, injection time, and stress anisotropy are discussed in detail. A quantitative relationship between fracture closure pressure and these factors is plotted to reduce or eliminate the errors caused by conventional fracture injection diagnostic models. The results show that leak-off rate, injection time, and stress anisotropy have a significant effect on the fracture closure process. Fracture closure in naturally fractured formations is a slow process, and the early closure pressure represents the closure of the branch fracture, which is much higher than the minimum horizontal stress. This investigation provides new insight into how to estimate the in-situ stress in naturally fractured reservoirs. [ABSTRACT FROM AUTHOR]

The frequent occurrence of casing failure has significantly affected the development of shale gas in the Sichuan Basin. Based on engineering and geology analyses, natural fracture/fault slip leads to casing shear deformation during hydraulic fracturing. Hence, natural fracture/fault slip and casing‐cement sheath‐formation assembly finite element models were established to quantitatively examine the characteristics of natural fracture/fault slip and mechanisms of casing shear deformation. Many factors, such as formation elastic property, in situ stress, natural fracture/fault geometry property, fluid pressure, casing elastic property, cement sheath elastic property, and well trajectory, were considered. The simulated results were in good agreement with the field data. The results indicated that natural fracture/fault slip leads to a sharp increase in casing deformation and stress in the adjacent region. Furthermore, factor sensitivity analysis results showed that a higher fluid pressure, larger fracture length, larger fracture dip angle, higher in situ stress difference, lower formation Young's modulus, and shorter distance from the wellbore to the center of the slip surface lead to severe casing stress and deformation. The countermeasures for preventing casing shear deformation involve decreasing the fracturing treatment pressure, reducing the crossing angle between the wellbore and natural fracture/fault, maintaining a safe distance from the wellbore to the large fracture/fault center, and adopting "balanced stress" fracturing operation. Hence, this study proposes a reasonable method to evaluate casing shear damage under hydraulic fracturing. [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 study of the shale rocks' fracturing characteristics reveal general guidelines for hydraulic fracturing processes in shale reservoirs, and the microseismic information provides a direct reflection of the fracturing process. Acoustic emission (AE) testing of rocks in the laboratory can be used for the application of microseismic information acquired in the field. Therefore, uniaxial compression experiments were performed to study AE characteristics during the failure process in shale rocks. In this study, the number of AE hits, along with the energy, a-values and b-values, were used to characterise the AE data and to describe the rock's rupture behaviour. The testing results indicated that the AE rates and energy values increased markedly when slippage occurred and these parameters reflect the generation of micro-cracks in the rock. The b and a-value curves can be divided into four stages corresponding with the fracture processes. The changes in the b and a -values can indicate the distribution characteristics of cracks within the rock. Based on this theory, the AE characteristics from dry and water-saturated shale samples under uniaxial compression were compared to demonstrate that water diffuses pressure in the rock and promotes fracture network generation. The b-values in the elastic-yield stage increase along with the brittleness index, and the b-values in the post-peak stage can offset the limitations of brittleness indexes used in evaluations of reservoir fracability. Exploring the law of rupture for shale under pressure provides a foundation for microseismic-based quantitative evaluation of the hydraulic fracturing stimulation efforts in shale reservoirs; therefore, this knowledge has both scientific and engineering significance. [ABSTRACT FROM AUTHOR]

To understand the influence of fluid saturation on the failure mode of gas shale, a series of triaxial compression tests under the quasi-static loading conditions were conducted using the GCTS (Geotechnical Consulting and Testing System) under different conditions (dry, water saturation, and slickwater saturation). The results showed that the rupture of dry shale samples was accompanied by a transient release of energy, which formed into the main splitting crack. Simultaneously, high-energy tension-type acoustic emission (AE) events were detected around the peak stress. Shale saturated with fluid decreased the strength and increased deformation. The presence of a “step” disturbance was clear in the expansion stage before rupture, and low-energy shear rupture events were detected repeatedly. This indicates that there were internal microslips and distributed micro-cracks to form, which maintained the overall integrity of the cores. Based on the analysis above, two failure modes were discovered: transient main crack failure mode for dry shale and distributed micro-failure mode for shale saturated with fluid. The effect of fluid saturation on the failure mode of shale was clear. This effect can increase the pore pressure; reduce fracture-surface energy; enhance the softening effect caused by water-absorbing clay, which reduced the effective stress on crack surfaces; promoted rock shear slip inside the rock; and changed the energy release characteristic and fracture mode of the shale under a stress condition, which were conducive to the formation of a crack network. The experimental results showed that saturated slickwater had a stronger effect on the failure mode of brittleness gas shale than that of saturated water. [ABSTRACT FROM AUTHOR]

Gas shale formation with extremely low porosity and permeability can only be developed economically by using a fracturing treatment to form spatial hydraulic fracture networks. Shearing slip is an important factor during fracture network formation and is controlled by the frictional strength of the fracture surface. A series of experimental studies were performed on shale's frictional coefficient, sliding behaviors and compressive shearing strength. The results showed that (1) normal stress has little effect on the sliding frictional coefficient, but the sliding mode is obviously changed with normal stress. Higher normal stress induces a smoother sliding. (2) Different shale exhibited different friction properties. When the clay content in shale is high enough (higher than 35% in this paper) and most of the clay minerals are smectite or an I/S mixed layer, a lower frictional coefficient will be observed (less than 0.6). Meanwhile, the shale's frictional coefficient was more sensitive to water. Slickwater with a resistance reducer additive can reduce the frictional coefficient to 0.36. (3) Absorbed water (e.g., by capillary force or osmotic pressure) inside the shale can activate the natural cracks in the shale and induce micro-slip under compressive stress conditions. The energy release process will be dispersively distributed, and complex fracture networks tend to form. These results are helpful in revealing the mechanisms of fracture networks formation in shale reservoirs under the combined effects of stress, fracturing fluid, and natural fractures. [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]

Degradable fiber can temporarily plug a natural fracture or artificial fracture. It has been successfully applied in the stimulated reservoir volume (SRV) fracturing or re-fracturing of unconventional reservoirs. Based on the classical analytical stress field equation, a new mathematical model is established in this paper to model the crack reorientation path after injecting fiber diversion fluid according to the tensile failure criterion. Factors influencing the diverting radius are intensively analyzed through numerical simulation. The results indicate that the horizontal stress difference, fracturing fluid viscosity, and injection time (fracturing fluid volume) have larger effects on the diverting radius than do the formation permeability (1–50 mD) and bottomhole pressure (90–160 MPa). The simulation results are successfully verified, matching well with the experimental data from the true tri-axial fracture reorientation tests in the laboratory. The model is successfully applied to the heterogeneous carbonate reservoirs in northwest China. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an effective stimulation method for the economic development of tight-gas reservoirs in which extremely low matrix permeability requires complex fracture networks. Petrophysical/mechanical experiments and XRD/SEM analyses demonstrate that volcanic sedimentary rock is characterized by developed natural fracture, strong brittleness, stress sensitivity, AE activity, weak anisotropy, and fluid sensitivity. Fracability index is often utilized as a key parameter to evaluate the ability to generate fracture networks. In this study, a new systematic experimental approach and a new mathematical model are established for the comprehensive evaluation of the fracability of tight-gas formations. These two methods integrate natural fracture, stress sensitivity, rock anisotropic nature, AE activity and crack density. The results indicate that the fracability index (FI) and the calculated crack density (CRD) are positively linearly correlated. The method is successfully applied to evaluate the fracability of the Yingtai gas field in northeast China. [ABSTRACT FROM AUTHOR]

Water uptake is an essential factor influencing the fate of fluids used during large-scale hydraulic fracturing in tight reservoirs. However, the relationship between water uptake and fracture generation in tight reservoirs is not well understood due to the special properties, such as extra-low porosity, permeability and high salinity. Water uptake, salinity evolution, and triaxial compression experiments were conducted on tight sandstone, shale, and volcanic rock to study the mechanisms of water uptake and its relationship with fracture generation. A new method for evaluating the generation of fractures based on the characteristics of water uptake was proposed. The results show that water uptake due to capillarity and osmosis leads to a decrease in rock compressive strength and Young's modulus but an increase in Poisson's ratio. The dilatancy of the sample changes with the water content for a similar lithology. With the increase of water uptake, the dilatancy of rock will occur earlier and more fractures will be produced. New fractures resulted from the high content of mixed layer of illite and smectite during water uptake lead to a significant increase in the salinity of the fracturing fluid. The difference in water uptake between matrix and fracture-matrix could increase with the larger contact areas and volume of fracture dilation. Owing to the larger contact areas between fractures and the fracturing fluid, the complex fractures lead to a larger final mass difference and more peak time of water uptake. The peak time and final mass difference of water uptake could reflect the generation and morphology of new formed fractures. This study is significant for hydraulic fracturing design and the evaluation of hydraulic fracture complexity in tight reservoirs. • The quantitative relationship between water uptake and fracture generation in tight reservoirs was revealed. • A new method for evaluating the generation of fractures based on the characteristics of water uptake was proposed. • The mechanical mechanisms of water uptake under the combined action of capillarity and osmosis were analyzed in detail. [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]

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]

Glutenite is composed of gravel, matrix and their cementing surface in meso-scale. The fracture propagation in it is therefore different from the fine-grained rocks such as shale and sandstone. In order to study the influence of mechanical contrast between the matrix and gravel on fracture propagation and mechanical properties of glutenite, three-point bending tests on semi-circular samples were performed. The results of three-point bending indicate that not all glutenite was enhanced by gravel on fracture toughness. Therefore, we classified the glutenite into gravel-enhanced and gravel-weakened. In gravel-enhanced glutenite, gravel increases the fracture toughness of the glutenite, and the fracture is characterized by deflection when it hits the gravel. In gravel-enhanced glutenite, the fracture is single and tortuous when gravel content is less than 35 % and bifurcate and tortuous when gravel content is more than 35 %. As for the gravel-weakened glutenite, gravel reduces fracture toughness of glutenite, and the fracture penetrates the gravel when it hits gravel, which leads to a single and flat fracture. The enhancing or weakening effect of gravel is caused by the mechanical contrast between the matrix and gravel. In gravel-enhanced glutenite, the hardness of gravel is higher than that of the matrix, and the gravel prevents fracture from propagating. While in gravel-weakened glutenite, there are large amounts of weak gravels whose hardness is lower than that of the matrix. Instead of preventing the fracture from propagating, the weak gravels are penetrated. Gravel content and support pattern also have an important effect on the mechanical properties of glutenite. When gravel content is less than 35 %, the gravel is not in contact with each other, the supporting phase is the matrix, and the mechanical properties of glutenite are therefore mainly controlled by the matrix. When gravel content rises above 35 %, gravel begins to contact with each other, and the contacted gravel forms a skeleton bearing the external load. In this case, the supporting phase changes from the matrix to gravel, resulting in a drastic variation of elastic modulus of glutenite as gravel content increases. According to gravel content and the hardness contrast between the matrix and gravel, glutenite was subdivided into four types. The main controlling factors of fracture propagation of the four types were clarified. This classification is of great significance in guiding hydraulic fracturing for different glutenite reservoirs. • The effect of mechanical contrast between the matrix and gravel on fracture propagation in glutenite was studied. •Mechanical contrast has an essential influence on both the propagation resistance and the fracture morphology. •We classified the glutenite as gravel-enhanced and gravel-weakened according to the mechanical contrast. •According to gravel content and the hardness contrast, glutenite was subclassified into four types. [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]