Fractured Shale Research Articles

Multi-Phases Fluid Activity Characteristics of Longmaxi Formation and Its Impact on Resistivity in the Changning Area, Southern Sichuan Basin, Southwest China

Wells with low gas content and low resistivity in the Changning area, southern Sichuan Basin were selected for this study. The burial-thermal history was reconstructed and the characteristics of multi-phase fluid activity were clarified using microscopic observation and testing of fluid inclusions in the Longmaxi shale fracture veins. Compared with wells with a high gas content and high resistivity, the influence of fluid activity on resistivity was analyzed. The results showed that the thermal evolution of the bituminous inclusions trapped in the veins has reached the stage of carbonaceous-metamorphic bitumen, and the organic matter is fully cracked for gas generation, with some organic matter exhibiting the phenomenon of “graphitization.” The synchronous fluid with bitumen was existed due to shallow burial with a middle-low maturity stage of about 280 and 292 Ma. Two phases of fluids existed in the deep burial stage, thus maturing for about 103 Ma, and the uplift stage at about 28 and 32 Ma, with high homogenization temperatures (Th) (varying from 185 to 195°C and 165–180°C). The corresponding pressure coefficients varied between 1.67 and 2.09, 1.56 and 1.92 in a moderate-strong high-pressure state. The last two phases of fluid formation in the late uplift stage for about 4 to 19 Ma and 6 to 10 Ma were characterized by low salinity at medium-low Th (varied from 140 to 155°C and 120–135°C), with pressures of 57.47–74.50 MPa and 51.44–59.41 MPa (pressure coefficients of 1.09–1.41 and 1.18–1.37), in an atmospheric-weak overpressure state. In the initial uplift stage after deep burial, the fluid closure in the Changning area was good. In contrast, the wells are filled with low gas content because of the strong tectonic forces causing the shale gas to be released and the multi-phase fluid activity that happens during the late uplift stage. New evidence indicates that the emergence of low resistance in the localized Changning area is not only related to the high degree of evolution of organic matter but is also affected by the multi-phase fluid modification in the late uplift stage.

Brittleness evaluation based on shale fracture morphology

Fracture morphology of shales represents the main feature related to their brittleness, and plays an important role in affecting the complexity of fracture network in shale reservoirs. However, no brittleness index model based on fracture morphology has been developed so far. In the present research, a detailed analysis on morphological characteristics of shale fractures under triaxial compression has been performed, focusing on the Longmaxi Formation shale in the Weiyuan area, China. As a next step, the fractal theory is used to establish a method to characterize fracture complexity. As a next step, the correlation between rock mechanics parameters, mineral composition, stress-strain curve, dilatability, and shale fracture complexity is analyzed, determining the most influencing factors affecting brittleness, whose weight is analyzed by applying the gray correlation method. Furthermore, a novel brittleness evaluation method based on shale fracture morphology is established. Results show that Young's modulus, peak strain, and dilatancy angle of shales are characterized by the highest correlation values with fracture morphology (0.4745, 0.6302, and 0.579, respectively), while Poisson's ratio, mineral composition, peak, and residual stress, and strain have little correlation. The calculation and analysis of a shale horizontal well using the brittleness index calculation method in this paper shows that the established method has a good correlation with the number of events of MS after fracturing, the reconstruction volume, which provides technical support for the optimization of fracturing sweet spot in shale horizontal wells, and the evaluation of shale reservoir compressibility.

Experimental Study on Hydraulic Fracturing of Bedding Shale Considering Anisotropy Effects.

The bedding plane formed by sedimentation makes shale anisotropic. To clarify the influence of bedding on the hydraulic fracturing of shale, the fracture characteristics of bedding shale were first clarified by conducting a hydraulic fracturing experiment on large-scale shale samples with different bedding angles. Subsequently, combined with the experimental results, based on the theory of elasticity, a new fracture initiation criterion for shale hydraulic fracturing considering its anisotropic characteristics was established. The influence of the bedding angle on the hydraulic fracture initiation pressure and initiation angle was analyzed. The results showed that the pump pressure curve during hydraulic fracturing can be divided into four stages: continuous pressurization, internal pressure drop, internal pressure attenuation, and internal pressure equilibrium stage. Corresponding to the four stages of the pump pressure curve, the evolution of hydraulic fracture has four processes: microfracture development, fracture initiation, fracture propagation, and fracture network equilibrium process. When the direction of the maximum principal stress is perpendicular to the bedding, a complex fracture network is easily formed. Depending on whether the bedding plane is open or not, the modes of interaction between the hydraulic fractures and bedding plane could be divided into eight types. Hydraulic fractures initiate in two ways: from the matrix and from natural fractures. During fracturing, with the increase in the bedding angle, the initiation pressure decreases gradually and the initiation angle decreases first and then increases. The knowledge gained in this study can provide data and theoretical support for drilling direction design and fracture pressure evaluation in the field of hydraulic fracturing.

Pore Structure of Oil Shale Heated by Using Conduction and Microwave Radiation: A Case Study of Oil Shale from the Fushun in China

To examine the evolution of the internal pore structure of and the law of changes in oil shale under different heating modes but at the same temperature, this study subjected φ 20 mm × 20 mm specimens of oil shale to temperatures in the range of 20°C ~500°C by using a muffle furnace and a microwave pyrolysis device. We carried out experiments on the pyrolysis reaction under different temperatures and used scanning electron microscopy, backscattering, the mercury intrusion test, and MATLAB for a refined characterization of the specimens. The results showed that the microwave pyrolysis of oil shale was much shorter than its conduction-induced heating. As the microwave power increased, the time required to reach the target temperature decreased. The phenomenon of “hole blocking” was observed at 400°C ~500°C during conduction-based heating but did not occur in the microwave pyrolysis of oil shale. The porosity of oil shale heated by conduction was 3.4 times higher than its original porosity, whereas that of oil shale heated by microwave radiation was 4.9 times higher than its original value. It can be seen that compared with conduction heating, radiant heating makes the pyrolysis of organic matter in oil shale more complete. During the pyrolysis process of oil shale, the complete reaction of organic matter causes the thermal fracture of the oil shale to produce a large number of pores and interconnected cracks. Thereby, a seepage channel for pyrolysis gas and oil is formed, and the recovery rate of oil and gas is increased.

Characterization of the fracture compressibility and its permeability for shale under the effects of proppant embedment and compaction: A preliminary study

Hydraulic fracturing technology plays a key role in improving the recovery rate of shale gas. The improvement of permeability in relation to hydraulic fracturing depends on changes brought about by the proppant on the fracture structure in reservoirs. Then it is of great significance to describe the microscopic changes during this process by means of an accurate theoretical model. In this study, based on the heterogeneity of shale fracture and the compaction and embedment of a proppant, we proposed a permeability model to examine the combined effects of a proppant and stress to describe the change mechanism in permeability. Further, changes in fracture width and porosity were considered, and a calculation model of fracture compressibility under proppant compaction and embedment was proposed. The difference from previous studies is that the compressibility and permeability of supported fractures can be further quantified and analyzed by this model. Moreover, its rationality was verified by publicly released test data. The results show that, the compressive effect of stress and the embedding of proppant both have a negative impact on shale permeability.

Effects of hydrostatic pressure on hydraulic fracturing properties of shale using X-ray computed tomography and acoustic emission

The study of the hydraulic fracturing characteristics in shale reservoirs is crucial for improving the permeability of shale gas reservoirs. In this study, hydraulic fracturing tests are conducted on full-diameter shale cores, and the hydraulic fracturing characteristics of shale with different bedding angles under high hydrostatic pressure are studied. The results show that under a hydrostatic pressure of 59 MPa, the shale sample will rupture twice in the breakdown stage during hydraulic fracturing. When the bedding inclination increases from 0° to 90°, the shale fracture breakdown pressure first decreases and then increases, showing an overall downward trend. Under high hydrostatic pressure, shale specimen surface fracture morphology and X-ray computed tomography reveal that a bedding angle close to 45° is more conducive to forming a complex hydraulic fracture network, which makes the fractal dimension of the fracture network larger. The bedding plane of shale is the direct cause of the diverse propagation patterns of hydraulic fractures. The b-value is a parameter that characterizes the magnitude–frequency relationship of an earthquake, and it is closely related to the rock rupture process. The b-value varies with different trends with the expansion of hydraulic fractures, but they all reach the lowest point before the failure of the shale sample. The higher the hydraulic fracture network complexity, the lower the peak b-value is. This work provides a qualitative understanding and scientific explanation of the hydraulic fracturing characteristics of anisotropic shale under hydrostatic pressure.

An experimental apparatus for supercritical CO2 fracturing of shale: System design and application tests

Supercritical CO2 (SC–CO2) would be a potential substitute for water-based fracturing fluid widely used in the present hydraulic fracturing of shale reservoirs. However, the field application of SC-CO2 fracturing is still in its infancy. Laboratory experiments are crucial for understanding the effects of various fracturing parameters and validating numerical simulations before conducting costly field trials. This paper first introduces the design of a self-developed experimental apparatus for fracturing cylindrical rock specimens and outlines the working principles of six functional modules. The entire experimental system is flexible because its functional modules can be used interchangeably. Subsequently, some key designs are emphasized. (1) A packer with the sealing of O and Y rings exhibits a good seal efficiency for a relatively small wellbore; moreover, this packer can be conveniently moved out from the fractured shale without damaging the specimen. (2) Downhole temperature measurement structure integrated into the packer can sensitively monitor the CO2 temperature variation at a high sampling rate during the entire SC-CO2 fracturing process. (3) The design of the triaxial core holder contributes to the realization of withstanding high axial-confining and fluid injection pressures and customized installation of acoustic emission (AE) sensors. Ultimately, some fracturing experiments with water and SC-CO2 as fracturing fluids and seepage tests with nitrogen (N2) under various test parameters are successfully conducted. The results indicate that, after the specimen fractures, the injection pressure would be approximately decreased to the confining pressure due to the confining chamber sealing design; there is a simultaneous sharp variation in the temperature at the bottom of the wellbore. SC-CO2 fracturing generates more fractures with greater bifurcation and higher tortuosity. The gas flow rate decreases with increasing confining pressure, whereas it increases significantly with increasing injection pressure. In general, these experimental results can validate the performance and feasibility of the self-developed experimental apparatus.

Influence of slip and permeability of bedding interface on hydraulic fracturing: A numerical study using combined finite-discrete element method

Shale is a common layered sedimentary rock containing bedding interfaces in oil and gas reservoirs. In hydraulic fracturing of shales, the fracturing fluid could flow into bedding interfaces and cause slipping, thus affecting the propagation of hydraulic fractures. Currently, the interaction mechanism between hydraulic fractures and bedding interfaces is still unclear because of the difficulty in monitoring fractures in laboratory experiments and the lack of appropriate numerical tools to model the dynamic hydraulic fracturing process. In this paper, the emerging combined finite-discrete element method (FDEM) is used to numerically study the main controlling factors of the interaction between hydraulic fractures and bedding interfaces, as it is known for its advantage of simulating material transition from intact solid to crack initiation and propagation. Our results show that the slip property of bedding interfaces determines whether hydraulic fractures can cross over bedding interfaces. Interestingly, the high permeability of bedding interfaces does not hinder the crossing but only delays the time needed for such crossing. We also find that both the slip type and permeability of bedding interfaces can give rise to a change in the width of hydraulic fractures when propagating across bedding interfaces, and result in a discontinuous distribution of local stress and fluid pressure near bedding interfaces accompanied by a strong stress shadow area. Therefore, in the process of hydraulic fracturing in reservoirs with bedding interfaces, the problem of multi-fracture interference could be more deteriorative. This paper aims to provide a new understanding of the hydraulic fracture crossing mechanism and hydraulic fracture morphology in reservoirs with bedding interfaces.

Fracture Characterization of Lower Cambrian Niutitang Shale in Cen’gong Block, Southern China

The marine shale of southern China is characterized by old sedimentary formations, multiple tectonic activities, and poor preservation conditions. The fracture system in this shale reservoir is extraordinarily complex, greatly adding to difficulties for shale gas exploration and development. Based on field surveys, drilling cores, seismic data interpretation, and experimental tests, we try to characterize the developmental characteristics of shale fractures at different scales and delineate the stages of fractures in the Cen’gong block. The results show that the Cen’gong block is a saddle-shaped structure formed by the northeast-oriented Banxi anticline and the southwest-oriented Lannigan anticline. There are four types of core fractures developed in the study area, namely, pyrite-filled fractures, fibrous veins, subvertical fractures, and slip fractures, and the forming time of these fractures are later in turn based on the intersecting relationships and analysis of filling minerals. The fracture rose diagram and the paleomagnetic orientation experiments indicate that the fracture direction is mainly NNE and partly NW, consistent with the direction of faults identified in the seismic data. Quantitative statistics have been conducted for fracture aperture, length, and density distribution. The fracture abundance has a close relationship with buried depth and regional faults in the study area.

Study on vertical multifracture propagations in deep shale reservoir with natural fracture network

AbstractBuilding a complex fracture network in a deep shale gas reservoir during multicluster hydraulic fracturing is challenging. On the one hand, hydraulic fractures tend to propagate along shale bedding planes, thus leading to a limited hydraulic fracture height; on the other hand, under the effect of high in situ stress and weak plane of fractures, multihydraulic fractures can hardly initiate and propagate uniformly. All of these will jeopardize the performance of hydraulic fracturing. This paper considers the influence of natural fracture network, shale beddings, fracturing‐fluid leakage, and high in situ stresses, and builds a numerical model to simulate multifracture propagations along vertical direction during hydraulic fracturing in deep shale reservoirs. The model is developed based on the theory of solid–fluid coupling and finite element method with pore pressure cohesive element technique are used to simulate multicluster fracture initiation and propagation. Moreover, the model is verified by published experiment data, and a good agreement between model and experiment results is observed. The influences of pump rate and fracturing‐fluid viscosity on fracture geometry are discussed, and the flow dynamics around each perforation cluster under different perforation parameters are also studied. Finally, suggestions to improve overall outcome of multicluster hydraulic fracturing are also provided.

Experimental study on the effects of steam temperature on the pore-fracture evolution of oil shale exposed to the convection heating

In the convection heating technology for shale oil recovery, steam is used as a transmission medium to pyrolyze oil shale. An experiment was designed to pyrolyze oil shale via steam injection in a large reactor. The samples of oil shale and semi-coke were obtained at different pyrolysis temperatures, and the pore-fracture structure of the samples was studied. The results showed that the average pore diameter and median pore diameter increased by about 10 times when the steam temperature increased from 314 °C to 555 °C. After completion of the steam pyrolysis, we observed that the internal fractures of oil shale were mainly microfractures. At the pyrolysis temperature of 555 °C, the number of microfractures in oil shale was more than 50 times compared with those observed at normal temperature. The micro-CT results indicated that the porosity of oil shale reached 15% after pyrolysis with high-temperature steam. At this porosity, the oil content of samples after pyrolysis was 0.05–0.22%, and the internal organic matter was completely pyrolyzed. Finally, the bedding planes of rock mass exhibited significant ruptures when the oil shale was pyrolyzed with high-temperature steam, thus providing proper channels for steam injection and flows of oil and gas.

Numerical simulation of hydraulic fracturing process with consideration of fluid–solid interaction in shale rock

As a critical technology for the efficient exploitation of shale gas, hydraulic fracturing is a two-way fluid-solid coupling interaction process of water-rock. The accurate water pressure calculation in single shale rock fracture during hydraulic fracturing is critical to the fluid-solid coupling analysis. This paper selected the fractured shale rock from the shale reservoir for analysis based on the Saint-Venant principle. Moreover, the water pressure in a single shale rock fracture was calculated by solving the Navier-Stokes equations. Meanwhile, a fluid-solid coupling model of fractured shale rock during hydraulic fracturing was established and evaluated the changing process of hydraulic fracturing. Our results show that in the hydraulic fracturing process, the changing process of water pressure in a single shale fracture with or without fluid-solid coupling is similar, and both have a water hammer effect. Single shale rock fracture opened instantly in an elliptical shape. The maximum instantaneous water pressure at the fracture tip considering fluid-solid coupling was 3.01 times the initial water pressure. The Mises stress at the fracture tip caused by the maximum instantaneous water pressure was 2.97 times the Mises stress at the fracture tip caused by the water pressure in the fracture after stable water pressure change. Mode Ⅰ fracture occurred in the fractured shale rock when high-pressure water rapidly invaded 2/3 of the length of the fracture. The findings in this study may help to understand the hydraulic fracturing mechanism in shale rock.

Surrogate-assisted hydraulic fracture optimization workflow with applications for shale gas reservoir development: a comparative study of machine learning models

Unconventional reservoirs have become the main alternative for increasing oil and gas reserves around the world. Owing to their ultralow permeability properties and special pore structure, hydraulic fracturing technology is necessary to realize the efficient development and economic management of unconventional resources. To maximize the production capacity of wells, several fracture parameters, including fracture number, length, width, conductivity, and spacing, need to be optimized effectively. The optimization of hydraulic fracture parameters in shale gas reservoirs generally demands intensive computations owing to the necessity of numerous physicalmodel simulations. This study proposes a machine learning (ML)–assisted global optimization framework to rapidly obtain optimal fracture parameters. We employed three supervised ML models, including the radialbasis function, K-nearest neighbor, and multilayer perceptron, to emulate the relationship between fracture parameters and shale gas productivity for multistage fractured horizontal wells. Firstly, several forward shale gas simulations with embedded discrete fracture models generate training samples. Then, the samples are divided into training and testing samples to train these ML models and optimize network hyper parameters, respectively. Finally, the trained ML models are combined with an intelligent differential evolution algorithm to optimize the fracture parameters. This novel method has been applied to a naturally fractured reservoir model based on the real-field Barnett shale formation. The obtained results are compared with those of conventional optimizations with high-fidelity models. The results confirm the superiority of the proposed method owing to its very low computational cost. The use of ML modeling technology and an intelligent optimization algorithm could greatly contribute to simulation optimization and design, prompting progress in the intelligent development of unconventional oil and gas reservoirs in China.

Experimental study of water imbibition characteristics of the lacustrine shale in Sichuan Basin

Through the stimulation method of large-scale hydraulic fracturing, the spontaneous imbibition capacity of the water phase in the shale reservoir has great influence on the effect of stimulation. Generally, the lacustrine shale has the characteristics of high clay minerals content, strong expansibility, development of nanopores and micro-pores, and underdevelopment of fractures, which leads to the unclear behavior of spontaneous imbibition of aqueous phase. The lacustrine shale of Da'anzhai Member and marine shale of Longmaxi Formation in Sichuan Basin were selected to prepare both the shale matrix sample and fractured shale sample, and the spontaneous imbibition experiment of simulated formation water was carried out. By means of an XRD test, SEM observation, nuclear magnetic resonance test and linear expansion rate test, the mineral composition, the structure of pores and fractures, the capacity of hydration and expansion of both lacustrine and marine shale are compared and analyzed. The results show that the average spontaneous imbibition rate of lacustrine shale is 60.8% higher than that of marine shale within the initial 12 hours of imbibition. The lacustrine shale has faster imbibition rate than the marine shale in the initial stage of spontaneous imbibition. However, the lacustrine shale has underdeveloped pores and fractures, as well as poor connectivity of pores. Besides, the strong hydration and expansion of clay minerals can easily lead to dispersion and migration of clay minerals on the fracture surface, which will plug up the seepage channels, resulting in poor capacity of spontaneous imbibition. The spontaneous imbibition rate in the middle and late stage of Lacustrine shale is obviously lower than that of the marine shale. The overall spontaneous imbibition rate ability of the lacustrine shale is less than that of the marine shale. According to the characteristics of water imbibition of lacustrine shale, considering the dual effects of hydration expansion of clay minerals on the effective reconstructed volume, the microfractures can be initiated and extended by fully utilizing the hydration of shale. Acidification treatment, oxidation treatment or high temperature treatment can be used to expand pore space, enhance water phase imbibition capacity and improve multi-scale mass transfer capacity of the lacustrine shale.

A Flownet-Based Method for History Matching and Production Prediction of Shale or Tight Reservoirs with Fracturing Treatment

Summary Based on a newly developed physics-based data-driven model FlowNet, this paper presents an effective method for history matching and production prediction of fractured shale or tight reservoirs without any prior information about fracture geometry. In this method, four types of well nodes including fracturing cluster nodes, fracture nodes, stimulated reservoir volume (SRV) nodes, and matrix nodes are allocated in the reservoir. Then, the reservoir model is simplified as a flow network composed of some 1D connection elements between these nodes. Some grids are divided on each connection element, and the grids on the same connection element are of equal width and permeability. Subsequently, a fully implicit nonlinear solver is used to solve flow equations in this FlowNet grid system to obtain pressure, phase saturation, and production rates, etc. Efficient history-matching procedure based on the FlowNet model of the fractured reservoir is used to determine the parameters of connection elements, and then fast production prediction can be conducted. Five numerical examples including single-well depletion, waterflooding development with natural fractures, multiple-well interference, three-phase flow, and an actual waterflooding field case validate that this presented FlowNet-based method can achieve good history matching and production prediction for various flow problems in shale or tight reservoirs with fracturing treatment, and the history-matched transmissibility and volume of connection elements can reflect the existence of high-conductivity fractures.

Numerical Simulation Study of Brittle Rock Materials from Micro to Macro Scales Using Digital Image Processing and Parallel Computing

The multi-scale, high-resolution and accurate structural modeling of rocks is a powerful means to reveal the complex failure mechanisms of rocks and evaluate rock engineering safety. Due to the non-uniformity and opacity of rocks, describing their internal microstructure, mesostructure and macro joints accurately, and how to model their progressive fracture process, is a significant challenge. This paper aims to build a numerical method that can take into account real spatial structures of rocks and be applied to the study of crack propagation and failure in different scales of rocks. By combining the failure process analysis (RFPA) simulator with digital image processing technology, large-scale finite element models of multi-scale rocks, considering microstructure, mesostructure, and macro joints, were created to study mechanical and fracture behaviors on a cloud computing platform. The Windows-Linux interactive method was used for digital image processing and parallel computing. The simulation results show that the combination of a parallel RFPA solver and digital image modeling technology can achieve high-resolution structural modeling and high-efficiency calculation. In microscopic simulations, the influence of shale fractures and mineral spatial distribution on the fracture formation process can be revealed. In the mesostructure simulation, it can be seen that the spatial distribution of minerals has an impact on the splitting mode of the Brazilian splitting model. In the simulation of a joined rock mass, the progressive failure process can be effectively simulated. According to the results, it seems that the finite element parallel computing simulation method based on digital images can simulate the multi-scale failure process of brittle materials from micro to macro scales. Primarily, efficient parallel computing based on a cloud platform allows for the multi-scale, high-resolution and realistic modeling and analysis of rock materials.

Effectiveness of cellulose polyanionic-based polymers on the measurement of rheological properties of water-based drilling fluids in high-pressure high-temperature fractured shale reservoirs

High-pressure, high-temperature fractured shale reservoirs are types of unconventional reservoirs that need proper drilling operations for adequate efficiency. Proper measurement of drilling fluid’s rheological properties is of importance for drilling operations that may increase the penetration rate on the one hand with proper design. Therefore, the success of drilling operations strongly depends on the proper design of drilling fluids. In this paper, we experimentally investigated the effect of potassium and sodium formate fluid on the rheological properties of drilling fluid for fractured shale core samples. The yield point and apparent viscosity for muds consisted of cellulose polyanionic and cellulose polyanionic-ultralow polymers higher than base muds. It indicates the effect of formate salts in increasing thermal stability. In addition, in polymer-based muds, more amounts of formate salts have been used, indicating the low fluid loss volume. Consequently, the shale recovery rate for potassium formate fluids is higher than sodium formate fluid.

An Experimental Analysis of Microcrack Generation during Hydraulic Fracturing of Shale

Hydraulic fracturing is commonly applied in the shale gas exploitation industry. However, the mechanical mechanism of permeability under fracturing has so far been unclear. In this study, an analysis of laboratory experiments on hydraulic fracture propagation and bedding plane reactivation in shale is presented. To investigate microcrack occurrence under fracturing, several small slices were collected from the fracture surface and scanned with a scanning electron microscope (SEM). It was found that observed microscopic microcracks could not be produced by fluid pressure as the latter generated compressive stresses at the site of microcracks. Rather, the microcracks were produced by tensile stress concentration in front of the propagating fracture. This implies that bedding plane reactivation was caused by fracture propagation along the plane. An analysis of microcrack lengths showed that shale exhibited anisotropy in fracture toughness with resistance to fracture propagation parallel to bedding planes being twice as small compared to resistance to fracture propagation in the direction normal to bedding planes.

Characteristics of fractures stimulated by supercritical carbon dioxide fracturing in shale based on acoustic emission monitoring

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.

Creep characteristics of a fracturing fluid-softened shale investigated by microindentation

The creep of shales affects the fracture conductivity, well production rate, and hence ultimate recovery of hydrocarbons from reservoir formations. This paper presents an experimental study of the creep characteristics of a shale softened by thermo-hydro-mechano-chemical (THMC) treatments that mimic the rock-fluid interactions affected by high temperature, high pressure, and hydraulic fracturing fluids. Microindentation was conducted to characterize the creep behavior of the THMC-treated specimens with the data analyzed by the Kelvin-Voigt (KV) and compliance methods, while X-ray diffraction and scanning electron microscopy were performed to analyze the compositional and microstructural changes respectively to aid interpretation of indentation measurements. Results show that the THMC treatments increase the creep rate by 46–162%, owing to the treatment-induced softening that varies with the treatment time and distance from the fluid-rock interface, while the Young's modulus and hardness decrease with both the THMC-treatment and creep durations. The softened zones become more viscous, as reflected by the decreased KV model's viscoelastic coefficients for the softened specimens. The higher creep rate of the softened zones is primarily attributed to the weakening in cementation bond and increase in microscale porosity due to the dissolution of carbonates. The findings help understand the mechanisms for creep deformation and pertinent proppant embedment in fractured shales, and hence can be used to predict shale gas production and optimize fracturing fluid additives and stimulants.