Fractured Shale Reservoirs Research Articles

Study on the Formation Mechanism of Fracture Network in Hydraulic Fracturing of Shale Reservoirs

Study on the Formation Mechanism of Fracture Network in Hydraulic Fracturing of Shale Reservoirs

Shale Fracture Static Stability Evaluation Method Based on 3D Discrete Fracture Model: A Case Study on the Luzhou Area in Southern Sichuan Basin, SW China

Abstract The stress interference in deep shale may lead to shale fracturing and instability and consequently results in engineering risks such as casing deformation in horizontal wells. Therefore, in the early stages of shale gas exploration and development, it is of great significance to evaluate the stability of shale fractures in advance. The stability evaluation of shale reservoir faults can be mainly divided into two categories at present: quantitative evaluation of single faults and qualitative evaluation of wide-range faults. The quantitative evaluation of single faults primarily relies on numerical simulation techniques, while the qualitative evaluation of wide-range faults primarily employs geophysical methods. Both methods are difficult to meet the needs of shale gas exploration and development. The shale fracture stability evaluation method based on 3D discrete fracture model which is developed in this article can quantitatively evaluate the static stability of wide-range shale fractures in the early stage of exploration and development. In this article, seismic geometric attributes were calculated, and fracture seismic facies was established by means of the Bayesian probabilistic cluster analysis method. Then, 3D discrete fracture modeling under the constraint of fracture seismic facies was performed to establish a discrete fracture model. Finally, according to the Mohr–Coulomb criterion, the shear stress and effective normal stress of discrete fracture were calculated by using the formation pressure data in other exploration and development results and the regional in situ stress obtained through seismic prestack inversion. And thus, the stability evaluation of the fractures in shale reservoirs was eventually completed. In addition, this method was verified by using the casing deformation points in some actual shale-gas horizontal wells, the actual small fault points, and microseismic data. It indicates that the method has higher accuracy and is better applicable to the early shale gas exploration and development.

Pressure Distributions and Flow Regimes: An Integrated Approach For CO2 Sequestration Project Design and Evaluation in Hydraulically Fractured Shale Reservoirs

This paper introduces an integrated approach for estimating the key parameters of CO2 storage projects in depleted hydraulically fractured shale reservoirs. The approach focuses deep insights into evaluating these projects based on the pressure distribution and flow regimes. The objective is reducing the uncertainties in the design and evaluation criteria of CO2 storage by better understanding the flow mechanisms in the porous media. This understanding helps in perfectly modeling CO2 distribution and characterizing the expected flow regimes.Several analytical models are developed for the pressure behavior of CO2 multi-size scale flow mechanisms. Diffusion flow, slip flow, adsorption flow, and Darcy and non-Darcy flow are all considered. The flow in the nano-size organic particles, the micro-size kerogen particles, and the macro-size matrix is analytically described. The flow inside natural fractures in the stimulated and unstimulated reservoir volume as well as the flow of CO2 in the hydraulic fractures are modeled. Several rectangular reservoir configurations, hydraulic fracture characteristics, and petrophysical properties of the matrix, kerogen, and organic matter are examined. An estimation model for the total volume of CO2 that could be stored in the depleted fractured reservoirs is presented. The contribution of the unstimulated and stimulated porous media as well as the hydraulic fractures to the total volume is determined by characterizing the flow regimes. Different models are proposed for the time at which CO2 reaches the hydraulic fracture tips, the borders between stimulated and unstimulated porous media, and the reservoir boundary. Profound explanations are introduced for the impact of the constrained pressure on the total capacity of the reservoirs for CO2 storage.The study has reached several conclusions. The characteristics of the organic matter, kerogen, and the micro-size scale matrix do not significantly impact the pressure distribution and flow regimes. Conversely, the pressure distribution and flow regimes are significantly impacted by the characteristics of the hydraulic and natural fractures. The hydraulic fractures may offer a reasonable capacity for CO2 storage, meanwhile, the capacity of stimulated and unstimulated reservoir volume is controlled by reservoir configuration and fracture spacing. The constrained pressure may strictly reduce the total capacity of CO2 storage in the reservoir. The total volume of the injected CO2 can be determined from the pressure point when the injection pulse has reached to reservoir boundary. Beyond this point, it is not recommended to inject CO2 as it could increase reservoir pressure more than initial pressure. The pressure of the depleted reservoir before injection is a key parameter in the design and evaluation of the CO2 storage in shale reservoirs.This study introduces a novel approach for the design and evaluation criteria of CO2 storage in depleted shale reservoirs. The approach uses the pressure distribution and flow regimes that could be observed in the multi-size scale components of the reservoirs. The study proposes several models for estimating CO2 geosequestration capacity in the hydraulic fractures, stimulated and unstimulated reservoir volume as well as the total storage capacity of the reservoirs. The approach confidently addresses the concerns regarding the applicability of unconventional resources for CO2 storage and the total capacity offered by these reservoirs for this purpose.

Experimental Investigation of the Influence of Composition Changes in Shale on Pore Structure and Fractal Characteristics under Different HCl Concentrations.

Acidification is a promising stimulation technique for improving the pore structure of low-permeability shale reservoirs and enhancing shale gas production. Variations in the mineral composition and acid concentration play a significant role in altering the pore systems in shale reservoirs, thereby affecting shale gas transport and production. To investigate the effect of shale composition on pore structure and fractal characteristics under hydrochloric acid (HCl) treatment, experiments were carried out on carbonate-rich (68%), carbonate-medium (45%), and carbonate-poor (2%) shales with different concentrations of HCl solution (1, 5, 10 wt %). X-ray diffraction (XRD), low-temperature nitrogen adsorption, and fractal theory were performed to investigate variations in mineral composition, pore structure, and fractal characteristics of the unreacted and reacted shales. The results illustrated that the HCl treatment significantly reduced the content of carbonate minerals, and the dissolution degree of carbonate minerals increased with the increase in HCl concentration. More meso- and macropores were generated for carbonate-rich and carbonate-medium shale, while more micro- and mesopores were generated in carbonate-poor shale, which led to the increase in total pore volume (TPV) and total specific surface area (TSSA) at different degrees. Moreover, the pore surface roughness (D 1) and structure complexity (D 2) were reduced with the increase of HCl concentration for carbonate-rich shale, while the alteration of D 1 and D 2 showed an opposite trend for carbonate-poor shale. Additionally, D 1 decreased and D 2 increased for carbonate-medium shale. Relevant results could provide theoretical references for the acid fracturing of shale reservoirs with varying mineral compositions.

Experimental study on microscopic production characteristics and influencing factors during dynamic imbibition of shale reservoir with online NMR and fractal theory

Dynamic imbibition and displacement between the matrix and fractures in shale reservoirs can significantly enhance oil recovery (EOR) following initial depletion. However, the microscopic production characteristics and seepage mechanisms at different pore scales during the dynamic imbibition process remain incompletely understood. In this study, we established an online physical simulation experiment method that combines dynamic displacement and imbibition based on nuclear magnetic resonance (NMR) and fractal theory, and a series of online NMR water flooding dynamic imbibition experiments were conducted. Through real-time dynamic monitoring of multiphase flow and migration behavior of crude oil in each stage of dynamic imbibition, the microscopic production characteristics and influencing factors were quantitatively studied from the recovery and residual oil saturation field distribution of different scale pores. Additionally, we developed a novel two-dimensional (2-D) NMR interpretation model to investigate the dynamic development characteristics of shale oil injection-imbibition-soaking-production integration, and the multiphase and multi-scale dynamic imbibition crude oil migration models were discussed. The results show that shale oil occurrence pores can be categorized into two types based on the corresponding production mode (imbibition + displacement). The water flooding dynamic imbibition process in shale reservoirs unfolds in three stages: strong displacement and weak imbibition stage characterized by the rapid production of large pores and fractures under displacement action; weak displacement and strong imbibition stage involving the slow production of small pores under reverse imbibition; and dynamic equilibrium stage characterized by weak displacement and weak imbibition. When viewing the entire water flooding dynamic imbibition process as an organism, it becomes imperative to maximize the recovery of large pores while ensuring the recovery degree of small pores. High permeability contributes to better pore throat connectivity and a greater imbibition and displacement production degree. The contribution of the.two production modes to the recovery of small and large pores increased by 4.67 % and 3.17 %, respectively. A negative correlation was observed between high displacement pressure and imbibition recovery, yet it is conducive to the contribution of displacement to total recovery. Notably, fractures can effectively reduce oil-water seepage resistance, and increase the contribution of displacement to recovery by 21.65 %. Finally.a positive correlation was noted between increased imbibition amount and free oil recovery, while residual oil gradually shifted towards adsorbed and organic matter-dominated forms, leading to decreased recoverability. Effectively utilizing the bridge flow conductivity of fractures, fluid imbibition displacement, and carrying effect is crucial for achieving optimal EOR. The findings provide theoretical support for clarifying the interaction between matrix-fracture imbibition and displacement and for the efficient development of shale oil.

Effect of bedding planes and property contrast between layers on the propagation mechanism of hydraulic fracture height in shale reservoirs

Bedding planes and property contrast between layers plays an important role in preventing hydraulic fracture height extension in shale reservoirs. However, the intrinsic causes of fracture containment have not been elucidated, and few studies have considered the effects of mixed factors on fracture height extension. Based on the continuum-discontinuum element method, a 3D hydraulic-mechanical coupling model was established to explore the influence mechanism of bedding planes, stress and modulus difference between layers, and mixing factors on fracture height extension in a transversely isotropic shale reservoir. Shear failure usually occurs preferentially when the fracture approaches the bedding plane, and the essential reason for fracture containment is that the shear slip on the bedding plane blunts the fracture tip. The stronger stress barrier formed by the higher minimum principal stress in adjacent formation effectively enables the fracture to terminate at the interlayer interface. The lower modulus in adjacent formation is more prone to rock initiation, but the larger elastic deformation absorbs the fracture tip stress and impedes height propagation. The comprehensive effect of bedding planes and property contrast between layers on fracture propagation is more complex than that of a single factor. When different factors have positive effects on fracture containment, the fracture is easier to terminate at the bedding plane. Otherwise, the dominant factor determines whether the fracture can be captured. No matter what the conditions, the pressure relief in the bedding plane can slow down the propagation rate. The findings can offer theoretical support for predicting fracture height during field fracturing in shale reservoirs.

The in situ stress prediction of a fractured shale reservoir based on amplitude variation with angle and azimuth inversion: A case study from Southwest China

In situ stress estimation of a shale reservoir is critical for the design of shale hydraulic fracturing and wellbore stability analysis. Fractured shales have orthogonal anisotropy (OA) because of the presence of vertical fractures and lamination. However, the existing in situ stress estimation method mainly focuses on transversely isotropic media. To accommodate orthogonally anisotropic media, an in situ stress estimation method is developed by using amplitude variation with angle and azimuth inversion and linear-slip theory. First, an orthogonal anisotropic medium is introduced to characterize the fractured shale by using a linear-slip model, and then we formulate a reflection coefficient approximation for OA media to perform the seismic inversion. Next, a fracture weakness inversion strategy that incorporates the vertically transverse isotropic background is developed to obtain the stiffness matrix of the media. Finally, the in situ stresses of the OA medium are formulated by using a stress-strain relationship. Inversion tests and a real data application indicate that our method is effective.

Analysis of Fracturing Expansion Law of Shale Reservoir by Supercritical CO2 Fracturing and Mechanism Revealing

The rapid expansion of reservoir fractures and the enlargement of the area affected by working fluids can be accomplished solely through fracturing operations of oilfield working fluids in geological reservoirs. Supercritical CO2 is regarded as an ideal medium for shale reservoir fracturing owing to the inherent advantages of environmental friendliness, excellent capacity, and high stability. However, CO2 gas channeling and complex propagation of fractures in shale reservoirs hindered the commercialization of Supercritical CO2 fracturing technology. Herein, a simulation method for Supercritical CO2 fracturing based on cohesive force units is proposed to investigate the crack propagation behavior of CO2 fracturing technology under different construction parameters. Furthermore, the shale fracture propagation mechanism of Supercritical CO2 fracturing fluid is elucidated. The results indicated that the propagation ability of reservoir fractures and Mises stress are influenced by the fracturing fluid viscosity, fracturing azimuth angle, and reservoir conditions (temperature and pressure). An azimuth angle of 30° can achieve a maximum Mises stress of 3.213 × 107 Pa and a crack width of 1.669 × 10−2 m. However, an apparent viscosity of 14 × 10−6 Pa·s results in a crack width of only 2.227 × 10−2 m and a maximum Mises stress of 4.459 × 107 Pa. Additionally, a weaker fracture propagation ability and reduced Mises stress are exhibited at the fracturing fluid injection rate. As a straightforward model to synergistically investigate the fracture propagation behavior of shale reservoirs, this work provides new insights and strategies for the efficient extraction of shale reservoirs.

Life Cycle Optimization of CO2 Huff ’n’ Puff in Shale Oil Reservoir Coupling Carbon Tax and Embedded Discrete Fracture Model

Summary Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.

Study on the Fracture Extension Pattern of Shale Reservoir Fracturing under the Influence of Mineral Content.

This study aimed to investigate the effect of the microstructure of shale on fracture initiation and extension during hydraulic fracturing. The Longmaxi Formation shale reservoir in the Sichuan Basin was considered as the research object; its structure was modeled from a microscopic perspective, and a zero-thickness cohesive unit was embedded within the solid unit. Numerical simulations were performed to study the effect of mineral content on the microextension of the hydraulic fracture, extension behavior, and evolution law of shale. The results showed that changes in the mineral content resulted in changes in the forces between molecules within the minerals, which, in turn, affected the shale's brittleness. The percentages of brittle mineral content in the Long I, II, and III reservoir sections are 60.37, 47.60, and 53.56%, respectively. The fracture initiation pressures of the three reservoirs were 29.22, 31.42, and 30.22 MPa, respectively, and a linear correlation was found between the fracture initiation pressures and the brittle mineral contents of the reservoir sections. An increase in the reservoirs' percentage of brittle mineral content facilitated the fracture initiation, with a corresponding gradual decrease in the resistance to fracture initiation. The pore pressures of the fractures in the three reservoirs after fracture initiation were 0.90, 1.18, and 1.00 MPa, respectively. The larger the percentage of brittle minerals was, the lower was the fracture pore pressure. The greater the length, number, area, and width of the cracks were, the more likely they were to form longer and wider cracks. Hence, reservoirs with a high percentage of brittle minerals should be prioritized as the target formations for hydraulic fracturing operations. The results of this study reveal how the mineral content affects the extension of microscopic hydraulic fractures in shale reservoirs. As such, this work can provide a theoretical basis for rationally selecting a hydraulic fracturing operation layer in shale gas reservoirs.

Effect of proppant injection condition on fracture network structure and conductivity

AbstractThe hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved.

Experimental investigation on forced imbibition characteristics of shale oil reservoir based on nuclear magnetic resonance method

After large-scale fracturing of shale reservoirs, the fracturing fluid will imbibe in the reservoir. In order to clarify the characteristics of imbibition and the distribution characteristics of crude oil in the stage of forced imbibition, this paper selects the core of some blocks in Qinghai and Gulong areas to carry out the shale forced imbibition experiment. Nuclear magnetic resonance technology is used to monitor the variation of crude oil. And the influence of core permeability and contact angle on forced imbibition is further analyzed. The results of the study show that the shale has a strong imbibition effect on the fracturing fluid. The content of oil phase in the core decreases, and the phenomenon of oil-water replacement occurs. Priority porosity for fracking fluids exists in the process of imbibition, where fracturing fluid preferentially enter smaller pores and can cause a short-term increase in the oil phase content in larger pores. With the continuous process of imbibition, the rate of imbibition oil gradually slowed down, and the fracturing fluid gradually permeates evenly into the rock sample. Both permeability and wettability affect the imbibition capacity of fracturing fluid in the forced imbibition stage.

Fracture propagation law of temporary plugging and diversion fracturing in shale reservoirs under completion experiments of horizontal well with multi-cluster sand jetting perforation

This study conducted temporary plugging and diversion fracturing (TPDF) experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion with multi-cluster sand jetting perforation. The effects of temporary plugging agent (TPA) particle size, TPA concentration, single-cluster perforation number and cluster number on plugging pressure, multi-fracture diversion pattern and distribution of TPAs were investigated. A combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures. The addition of fibers can quickly achieve ultra-high pressure, but it may lead to longitudinal fractures extending along the wellbore. The temporary plugging peak pressure increases with an increase in the concentration of the TPA, reaching a peak at a certain concentration, and further increases do not significantly improve the temporary plugging peak pressure. The breaking pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number. A lower number of single-cluster perforations is beneficial for increasing the breaking pressure and temporary plugging peak pressure, and it has a more significant control on the propagation of multi-cluster fractures. A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures, while a higher number of clusters makes it difficult to achieve effective plugging. The TPAs within the fracture is mainly concentrated in the complex fracture areas, especially at the intersections of fractures. Meanwhile, the TPAs within the segment are primarily distributed near the perforation cluster apertures which initiated complex fractures.

Research on Evolutionary Laws of Mechanical Properties and Pore Structure during CO2 Pre-Injection Fracturing in Shale Reservoirs

CO2 pre-injection fracturing is a promising technology for shale reservoirs development, with multiple advantages for improving the complexity of fractures, the production of crude oil, and the sequestration of CO2. Previous research mostly focused on the CO2 effect on macroscopic mechanical properties of shale. However, there are many phenomena closely related to shale micro mechanical behavior. Therefore, this study presents a systematic investigation into the effects of CO2 on both macro and micro mechanical properties, as well as pore-fracture structures during CO2 pre-injection fracturing in shale reservoirs. The results show that CO2 can significantly decrease the tensile strength, uniaxial compressive strength, and elastic modulus of shale. With the increasing CO2 treatment time, the macro mechanical properties of shale decrease gradually. The microscopic experiments show that this significant decrease may be due to two mechanisms. The first is the significant decrease in the micro-mechanical properties of shale. The results of indentation analysis show that the microscopic elastic modulus and hardness of shale decrease by 51.3% and 63.3% after CO2 treatment. The second is the changes of the original shale framework. Pore-fractures structure analysis showed that after CO2 treatment, a large number of dissolution pores are generated in the shale matrix. Meanwhile, there are propagation of original fractures and opening of structural weak planes, which lead to the form of new fractures. Under the action of these two mechanisms, the macro mechanical strength of shale is reduced significantly. Therefore, in the field application, proper soaking following CO2 injection could lead to a significant overall reduction in mechanical strength, potentially lowering formation breakdown pressure, easing the requirements for treatment equipment, and enhancing fracturing effects.

Experimental study on the pseudo threshold pressure gradient of supported fractures in shale reservoirs

Pseudo threshold pressure gradient (PTPG) exists in the propped fractured reservoir, but its nonlinear flow law remains unclear. The effects of the mineral composition of shale and microstructure of fracturing fluid on PTPG were analyzed by X-ray diffraction and liquid nitrogen quick-freezing method. The results demonstrate that a proppant with a large particle size is more likely to form an effective flow channel and reduce liquid flow resistance, thus decreasing PTPG and increasing conductivity. The polymer fracturing fluid with rectangular microstructures significantly increased the PTPG supporting the fractured core. Experimental results show that the PTPG of the resin-coated sand-supported core in the fracturing fluid with a concentration of 1.2% is 245 times higher than that in the fracturing fluid with a concentration of 0.1% when the confining pressure is 5 MPa. Wetting hysteresis and the Jamin effect are responsible for the rise of PTPG in two-phase flow. The equivalent fracture width shows a good power function relationship with the PTPG. Thus, this study further explains the nonlinear flow behavior of reservoirs with fully propped fractures.

STUDY OF MICROSCALE PORE STRUCTURE AND FRACTURING ON THE EXAMPLE OF CHINA SHALE FIELD

Accurate characterization of pores and fractures in shale reservoirs is the theoretical basis for effective exploration and development of shale oil and gas. Currently, the scientific community has developed methods for determining the characteristics of the pore and fracture structure of shales with different resolutions, and also discussed the mechanisms of the influence of the characteristics of pores and cracks on the filtration of shale oil and gas. In this work, firstly, a three-dimensional model of a variable-scale pore-fracture structure was created. Secondly, on the basis of data obtained using computed tomography, the characteristics of the development of pores and cracks at different geometric sizes (25 and 2 mm) were statistically analyzed. Third, pore and fracture structures of mixed, felsitic and laminated felsitic shale have been relatively studied. The results show that: (a) the fractured porosity of group I felsite shale is 0.36–0.89 %; mixed shale of group I is 0.34–0.47 %; mixed shale of group III is 0.12–0.86 %; mixed shale of group III is 0.13–0.15 %. (b) Compared to mixed shale of group I, fracturing in felsite shale of the same group is more developed. In addition, the average fractured porosity of felsite shale is 0.28 % greater than that of mixed shale. After analyzing group III, it was noticed that the cracks of the mixed dolomite shale are less developed compared to the mixed shale of the same group, while the average porosity of the cracked shale is 0.33 % less than that of the cracks of the mixed shale (c). Various components of shale samples are distinguished on a gray scale. High density components are bright white (e.g. pyrite); medium density components — light gray (for example, quartz, carbonate and clay minerals); low-density components — dark gray (for example, organic matter); cracks — black (d). The volume of matrix components is relatively high and constitutes the bulk of the total volume of shale samples. The distribution of high-density minerals has a certain randomness. High-density ellipsoidal or irregular minerals (mainly pyrite) range in diameter from a few microns to hundreds of microns, and their volume is relatively small (e). Three types of microscale fractures are mainly developed in shale: microscale fractures within mineral particles (intragranular fractures), microscale fractures between mineral particles (intergranular fractures), and shrinkage fractures. Intragranular cracks are mainly microscale cracks formed by rigid particles that collapse in a certain direction under stress.

A new rock physics model for fractured oil shale reservoirs in Mahu oil field

The exploration of unconventional reservoirs such as oil shale has become a focus of research in the oil/gas industry, but due to the diversity of lithology and structural complexity of shale reservoirs, the study of their rock physics laws is a challenge. By analyzing the physical, lithologic, and fluid characteristics of oil shale reservoirs in the Mahu area of Xinjiang, China, we adopted a variety of effective-medium theories to carry out rock physics modeling. We analyzed the differences in the calculation results of various theoretical models, and finally constructed a set of rock physics modeling processes suitable for oil shale reservoirs. The analysis shows that the calculation results of Voigt-Reuss-Hill (VRH) and Hashin-Shtrikman (HS) average for mixed mineral matrix are very similar, but there are certain differences between the upper and lower bounds calculated by them. The upper and lower bounds of HS average are closer than VRH average. We used the Kuster-Toksoz effective-medium, differential effective-medium (DEM), and self-consistent approximation models to construct the rock skeleton and analyzed the differences of the models. The results of the three models are almost identical, but their assumptions and limitations differ. We used DEM in the final shale model, considering the large porosity and the order of inclusion filling. According to the fracture distribution characteristics of oil shale reservoirs, we used an inclined fracture model to describe the fractures with different structural characteristics. Finally, the established shale rock physics model was used to calculate the actual logging data, and the results of elastic parameters are consistent with the measured data. Through the inversion of the fracture parameters, the inversion results are consistent with the measured results as a whole, indicating that the model has certain applicability to the simulation of oil shale reservoirs.

Further Investigation of CO2 Quasi-Dry Fracturing in Shale Reservoirs—An Experimental Study

The physical properties of shale reservoirs are typically poor, necessitating the use of fracturing technology for effective development. However, the high clay content prevalent in shale formations poses significant challenges for conventional hydraulic fracturing methods. To address this issue, CO2-based fracturing fluid has been proposed as an alternative to mitigate the damage caused by water-based fracturing fluids. In this paper, the applicability of quasi-dry CO2 fracturing in shale reservoirs is examined from three key perspectives: the viscosity of CO2 fracturing fluid, the fracture characteristics induced by the CO2 fracture fluid, and the potential reservoir damage caused by the fracturing fluid. Firstly, the viscosity of CO2 fracturing fluid was determined by a rheological experiment. Rheological tests revealed that the viscosity of CO2 fracturing fluid was significantly influenced by the water–carbon ratio. Specifically, when the water–carbon ratio was 30:70, the maximum viscosity observed could reach 104 mPa·s. Moreover, increasing reservoir temperature resulted in decreased fracturing fluid viscosity, with a 40 °C temperature rise causing a 20% viscosity reduction. Secondly, matrix permeability tests were conducted to investigate permeability alteration during CO2 fracturing fluid invasion. Due to the weak acidity of CO2-based fracturing fluid, the permeability reduction induced by clay hydration was inhibited, and an increase in permeability was observed after a 3-day duration. However, the matrix permeability tends to decrease as the interaction time is prolonged, which means prolonged soaking time can still cause formation damage. Finally, triaxial fracturing experiments facilitated by a three-axis servo pressure device were conducted. The fracture properties were characterized using computed tomography (CT), and 3D reconstruction of fractured samples was conducted based on the CT data. The results demonstrate that CO2 fracturing fluid effectively activates weak cementation surfaces in the rock, promoting the formation of larger and more complex fractures. Hence, CO2 quasi-dry fracturing technology emerges as a method with significant potential, capable of efficiently stimulating shale reservoirs, although a reasonable soaking time is necessary to maximize hydrocarbon production.

Anisotropic Mechanical Behaviors of Shale Rock and Their Relation to Hydraulic Fracturing in a Shale Reservoir: A Review

Shale gas is an important supplement to the supply of natural gas resources and plays an important role on the world’s energy stage. The efficient implementation of hydraulic fracturing is the key issue in the exploration and exploitation of shale gas. The existence of bedding structure results in a distinct anisotropy of shale rock formation. The anisotropic behaviors of shale rock have important impacts on wellbore stability, hydraulic fracture propagation, and the formation of complex fracture networks. This paper briefly reviews previous work on the anisotropic mechanical properties of shale rock and their relation to hydraulic fracturing in shale reservoirs. In this paper, the research status of work addressing the lithological characteristics of shale rock is summarized first, particularly work considering the mineral constituent, which determines its physical and mechanical behavior in essence. Then the anisotropic physical and mechanical properties of shale specimens, including ultrasonic anisotropy, mechanical behavior under uniaxial and triaxial compression tests, and tensile property under the Brazilian test, are summarized, and the state of the literature on fracture toughness anisotropy is discussed. The concerns of anisotropic mechanical behavior under laboratory tests are emphasized in this paper, particularly the evaluation of shale brittleness based on mechanical characteristics, which is discussed in detail. Finally, further concerns such as the effects of bedding plane on hydraulic fracturing failure strength, crack propagation, and failure pattern are also drawn out. This review study will provide a better understanding of current research findings on the anisotropic mechanical properties of shale rock, which can provide insight into the shale anisotropy related to the fracture propagation of hydraulic fracturing in shale reservoirs.

Experimental investigation to understand the effect of fracturing fluid on the geomechanical behavior of mowry shale

Hydraulic fracturing of shale reservoirs is one of the important technologies in the oil and gas industry. To ensure the safe operation of oil and gas recovery, it is important to study the shale-fluid interactions on the geomechanical behavior of shale. This study investigated the effect of fracturing fluid treatment on the mechanical and elastic properties of the Mowry Shale formation, Wyoming, USA. Cylindrical Mowry Shale specimens with a diameter of 12.5 mm collected from the United States Geological Survey (USGS) and School of Energy Resources (SER) of the University of Wyoming were treated with brine and brine + stimulation fluid for one month each at pressures of 9 and 11.7 MPa and temperatures of 96 and 66 °C, respectively. Triaxial compression experiments were conducted on the specimens. Results showed that all Mowry Shale specimens experienced an increase in maximum volumetric strain with the increase in effective confining pressure (Pd). Regardless of aging fluids, the maximum deviatoric stress (Δσd) of most Mowry Shale specimens increases with the increase in Pd. At a lower Pd, the USGS specimen aged with brine and stimulation fluid exhibits higher maximum Δσd than those aged with brine only. However, at a higher Pd, the USGS specimen aged with brine exhibits a higher maximum Δσd. SER specimens aged with brine and stimulation fluid exhibit higher maximum Δσd values than those aged with brine for all three Pd values. Regardless of the aging fluids, most USGS specimens experience a brittle failure mode, while SER specimens aged with brine and stimulation fluid experienced a more ductile behavior.