Pre-existing Natural Fractures Research Articles

Numerical Analysis of the Stress Shadow Effects in Multistage Hydrofracturing Considering Natural Fracture and Leak-Off Effect

As a critical technological approach, multistage fracturing is frequently used to boost gas recovery in compact hydrocarbon reservoirs. Determining an ideal cluster distance that effectively integrates pre-existing natural fractures in the deposit creates a fracture network conducive to gas movement. Fracturing fluid leak-off also impacts water resources. In our study, we use a versatile finite element–discrete element method that improves the auto-refinement of the grid and the detection of multiple fracture movements to model staged fracturing in naturally fractured reservoirs. This computational model illustrates the interaction between hydraulic fractures and pre-existing fractures and employs the nonlinear Carter leak-off criterion to portray fluid leakage and the impacts of hydromechanical coupling during multistage fracturing. Numerical results show that sequential fracturing exhibits the maximum length in unfractured and naturally fractured models, and the leak-off volume of parallel fracturing is the smallest. Our study proposes an innovative technique for identifying and optimizing the spacing of fracturing clusters in unconventional reservoirs.

A Dynamic Propagation Numerical Model of Hydraulic Fracture Interactions with Pre-Existing Complex Natural Fractures

The propagation of hydraulic fractures is highly influenced by the geological structure of the reservoir in unconventional reservoirs, such as natural fractures. In this paper, a new fluid–solid coupling dynamic model was built which presents the failure mechanism of hydraulic fracture with pre-existing simple and complex natural fractures. The cohesive element method and the maximum principal stress fracture criterion were used in the new model. An analysis was conducted to investigate the impact of various factors, including encounter angle, in situ stress, elastic modulus, and Poisson’s ratio, on the propagation of hydraulic fractures. The simulation results indicate that the encounter angle and the in situ stress are the main factors affecting the fracture morphology. When the encounter angle and the in situ stress difference are small, hydraulic fractures propagate along natural fractures. When the elastic modulus is small, it is advantageous for the advancement of both hydraulic and natural fractures. The Poisson’s ratio has a slight effect on the fracture propagation pattern.

Influence of non-intersecting cemented natural fractures on hydraulic fracture propagation behavior

Fractures in deeply buried or formerly deeply buried rocks commonly contain mineral deposits having varying degrees of strength. Understanding how cement deposits in fractures interact with hydraulic fractures (HFs) is important for hydraulic fracture design for practical engineering applications such as enhanced geothermal fluid circulation or oil and gas production. Using discrete element methods, we describe a fully fluid-solid coupling numerical model simulating hydraulic fracture propagation to investigate the influence of cemented natural fractures (CNFs) that do not intersect the predicted path of hydraulic fractures on HF propagation morphology. The fracture morphology depicted by the numerical model aligns well with analytical solutions, indicating the reliability of the simulation results. Using this model, we delved into the effects of fracture cement strength and position, fracturing fluid viscosity, and induced stress field on the interactive propagation patterns of fractures. The simulation results indicate that the HF is captured by weakly non-intersecting CNF, causing the activation of the CNF and the development of cracks primarily caused by tensile failure. As the HF approaches the CNF, the induced tensile stress region at the fracture tip offsets toward the CNF, resulting in fracture reorientation. When the cementing strength ratio between pre-existing natural fracture and reservoir matrix is less than 0.5, it is beneficial to activate CNF and enhance reservoir permeability. The seepage of low-viscosity fracturing fluid into the reservoir significantly enhances the ability of the HF and non-intersecting CNF to communicate with each other, thereby providing favorable pathways for oil and gas flow. The research findings offer valuable insights into fracture network connectivity and permeability enhancement, contributing to enhanced reservoir stimulation strategies.

2D Phase-Field Modelling of Hydraulic Fracturing Affected by Cemented Natural Fractures Embedded in Saturated Poroelastic Rocks

AbstractThe interaction between a propagating hydraulic fracture (HF) and a pre-existing natural fracture (NF) embedded in saturated poroelastic rock formations is studied numerically in 2D plane–strain configurations. In this study, the phase-field method is further developed to be employed for modelling the HF propagation and the evolution of tensile and shear failure in geo-materials as gradient-type diffusive damaged zones. The shear slippage and dilation mechanisms inside the cemented NF are modelled using a Mohr–Coulomb–Griffith failure criterion that fitted in the framework of the phase-field fracture using appropriate energy functionals. The most important factors controlling the HF–NF interaction outcome are the approaching angle, differential in-situ stress, and hydro-mechanical characteristics of the NF. It is found out that higher tensile and shear strengths of the cemented NF are in favour of the crossing outcome when the differential stress is high enough to mobilise the resisting shear stresses against the slippage. Small hydraulic aperture (low hydraulic conductivity) for the NF is also in favour of the crossing outcome which helps to restrict the pressurised region local to the HF tip, lowering the possibility of shear slippage in the NF and the HF’s diversion. It is also concluded that the injection rate and the viscosity of fracturing fluid are operative factors to be adjusted for increasing the chance of crossing, a critical element for successful operation of hydraulic fracturing for effective use of subsurface energy resources.

Slip Activation Potential of Fractures in the Crystalline Basement Rocks of Kuujjuaq (Nunavik, Canada) to Assess Enhanced Geothermal Systems Development

This work presents an estimate of the slip activation potential of existing fractures in a remote northern community located on Canadian Shield rocks for geothermal purposes. To accomplish this objective, we analyzed outcrop analogues and recorded geometrical properties of fractures, namely the strike and dip. Then, we estimated the stress regime in the study area through an empirical approach and performed a probabilistic slip tendency analysis. This allowed us to determine the slip probability of the pre-existing fractures at the current state of stress, the orientation of fractures that are most likely to be activated and the fluid pressures needed for the slip activation of pre-existing fractures, which are key aspects for developing Enhanced Geothermal Systems. The results of this simple, yet effective, analysis suggest that at the current state of stress, the pre-existing natural fractures are relatively stable, and an injection pressure of about 12.5 MPa/km could be required to activate the most optimally oriented fractures to slip. An injection of water at this pressure gradient could open the optimally oriented pre-existing fractures and enhance the permeability of the reservoir for geothermal fluid extraction. The information described in this paper provides a significant contribution to the geothermal research underway in remote northern communities.

On poroelastic strain energy degradation in the variational phase-field models for hydraulic fracture

Though a number of formulations have been proposed for phase-field models for hydraulic fracture in a fully saturated porous medium, the definition of the degraded poroelastic strain energy varies from one model to another. This study explores previously proposed forms of the poroelastic strain energy with diffused fracture and assesses their ability to recover the explicit fracture opening aperture. We then propose a new form of degraded poroelastic strain energy derived from micromechanical analyses. Unlike the previously proposed models, our poroelastic strain energy degradation depends not only on the phase-field variable (damage) but also on the type of strain energy decomposition. Comparisons against closed form solutions suggest that our proposed model can recover crack opening displacement more accurately irrespective of Biot’s coefficient or the pore-pressure distribution. We then verify our model against the plane strain hydraulic fracture propagation, known as the KGD fracture, in the toughness dominated regime. Finally, we demonstrate the model’s ability to handle complex hydraulic fracture interactions with a pre-existing natural fracture.

Assessment of inherent heterogeneity effect on continuous mechanical properties of shale via uniaxial compression and scratch test methods

Shale reservoirs have been a significant focus of hydrocarbon production over the past few decades, and the mechanical assessment of target shale reservoirs has been critical to successful field operations, especially in hydraulic fracturing and well completions. The Unconfined compressive strength (UCS) and Poisson's ratio (ν) are critical mechanical properties in shale reservoir assessment. The estimation and measurement of shale mechanical properties are often erroneous by not accounting for their heterogeneous and pre-existing features, which yield variability of shale mechanical properties along their lithostratigraphy. Thus, there is a need to investigate the degree of correlation and accuracy in multiscale mechanical evaluations of heterogeneous shales, and the correlation between such micromechanical and macromechanical measurements. This study investigated the impact of inherent heterogeneity on the measurement of continuous micromechanical and macromechanical properties of shale reservoirs using scratch test (ST) and uniaxial compression test (UCT) methods, and the degree of correlation (correlation coefficient, r) of measurements in shale was further assessed for the variability of their measured properties. Shale core samples from three distinct shale formations were utilized and studied, and the core samples were subjected to ST and UCT, respectively. The results from this study showed that despite inherent heterogeneous anomalies and natural fractures in the shale samples analyzed, there is a good degree of correlation (UCS: r ​= ​0.73; ν: r ​= ​0.89) in the micro- and macro-mechanical properties of shales using two independent experimental tests (ST and UCT). This study provides insights for improving the accuracy of mechanical evaluations and numerical modeling in shales with a high degree of heterogeneity and pre-existing natural fractures. The results indicate that when considering the structural complexity and heterogeneity of unconventional reservoirs such as shales, the ST method can provide a better continuous micromechanical assessment of shales. In contrast, the UCT can provide a better bulk macromechanical measurement of shales.

Using in-situ strain measurements to evaluate the accuracy of stress estimation procedures from fracture injection/shut-in tests

Fracture injection/shut-in tests are commonly used to measure the state of stress in the subsurface. Injection creates a hydraulic fracture (or in some cases, opens a preexisting fracture), and then the pressure after shut-in is monitored to identify fracture closure. Different interpretation procedures have been proposed for estimating closure, and the procedures sometimes yield significantly different results. In this study, direct, in-situ strain measurements are used to observe fracture reopening and closure. The tests were performed as part of the EGS Collab project, a mesoscale project performed at 1.25 and 1.5 km depth at the Sanford Underground Research Facility. The tests were instrumented with the SIMFIP tool, a double-packer probe with a high-resolution three-dimensional borehole displacement sensor. The measurements provide a direct observation of the fracture closure signature, enabling a high-fidelity estimate of the fracture closure stress (ie, the normal stress on the fracture). In two of the four tests, injection created an opening mode fracture, and so the closure stress can be interpreted as the minimum principal stress. In the other two tests, injection probably opened preexisting natural fractures, and so the closure stress can be interpreted as the normal stress on the fractures. The strain measurements are compared against different proposed methods for estimating closure stress from pressure transients. The shut-in transients are analyzed with two techniques that are widely used in the field of petroleum engineering – the ‘tangent’ method and the ‘compliance’ method. In three of the four tests, the tangent method significantly underestimates the closure stress. The compliance method is reasonably accurate in all four tests. Closure stress is also interpreted using two other commonly-used methods – ‘first deviation from linearity’ and the method of (Hayashi and Haimson, 1991). In comparison with the SIMFIP data, these methods tend to overestimate the closure stress, evidently because they identify closure from early-time transient effects, such as near-wellbore tortuosity. In two of the tests, microseismic imaging provides an independent estimate of the size of the fracture created by injection. When combined with a simple mass balance calculation, the SIMFIP stress measurements yield predictions of fracture size that are reasonably consistent with the estimates from microseismic. The calculations imply an apparent fracture toughness 2-3x higher than typical laboratory-derived values.

Numerical modeling of low-frequency distributed acoustic sensing signals for mixed-mode reactivation

In recent years, the development of distributed acoustic sensing (DAS) technology has enabled direct monitoring of subsurface strain during hydraulic fracturing (HF) operations. Most low-frequency (<1 Hz) DAS (LFDAS) signals exhibit strain or strain-rate patterns that are characteristic of propagating tensile hydraulic fractures. However, mixed-mode fault reactivation, consisting of shear slip (mode II) with tensile opening (mode I), can occur in cases where propagating hydraulic fractures intersect preexisting natural fractures or faults. In this study, we show an anomalous LFDAS signal that was observed during an HF operation, with characteristics that differ from typical signals from tensile hydraulic fractures. Anomalous characteristics include the onset of an asymmetric compression-extension doublet after pumping was terminated. The location of the signals, coupled with the image log and seismic data, suggests that mixed-mode reactivation occurred on a preexisting fault. We use a simplified numerical model based on the displacement discontinuity method (DDM) to simulate the anomalous LFDAS signal. Results find that the first-order characteristics of the anomalous signal can be approximated as an initial tensile fault opening (mode I) followed by a shear slip (mode II) on a fault. Therefore, we demostrate the approach of using DDM to investigate mixed-mode fault reactivation during HF operations.

Phase field method to model hydraulic fracturing in saturated porous reservoir with natural fractures

In the present work, phase field model has been implemented for simulating hydraulic fracturing in porous reservoir which consists of several poorly connected natural fractures. We have used the finite element method (FEM) for solving the poro-elastic deformation and phase field equation, while the finite volume method (FVM) has been considered for solving the flow field. The validations of the numerical model with existing analytical and numerical solutions of fracture propagation are presented for an elastic medium subjected to incremental external loads and a poro-elastic medium undergoes hydraulic fracturing due to the increase of fluid injection pressure. The simulation results in this study show the ability of the phase field method based hydraulic fracturing (HF) model to obtain complex fracture propagation patterns including crack branching, merging, curving, and interacting with pre-existing natural fractures. Numerical simulation results suggest that for high injection pressure it is possible to get crack branching which is a desirable in the context of hydraulic fracture to create multiple high permeable flow paths with improved connectivity among the natural fractures for fluid circulation among injection and production wells. In the present study the values of aperture along the newly created hydraulic fracture and pre-existing fracture are determined from the displacement and phase fields at the end of hydraulic fracture simulations. The enhancement of effective transmissivity of the reservoir after hydraulic fracturing is compared for different network of pre-existing natural fracture. These results may be very insightful for industrial applications of hydraulic fracturing.

Uniquely determine fracture dimension and formation permeability from diagnostic fracture injection test

Estimating formation permeability is crucial for production estimation, hydraulic fracturing design optimization and rate transient analysis. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent, which can cast significant uncertainties in interpreting DFIT data. Without knowing the fracture dimension prior, open fracture stiffness/compliance can't be determined, which is required for formation permeability estimation. Previous work has to assume a fracture radius or fracture height in order to estimate formation permeability, thus dent the confidence in the interpretation results. In the study, we present a new approach to determine fracture dimension, leak-off coefficient and formation permeability uniquely based on material balance and basic fracture mechanics, using data from shut-in to after-closure linear flow. Field examples are also presented to demonstrate the simplicity and effectiveness of this new approach.

Validation of Estimating Stress from Fracture Injection Tests Using Continuous Wavelet Transform with Experimental Data

The article discusses the new technique for fracture closure pressure detection using continuous wavelet transform (CWT). The study focuses on calibrating the CWT technique and comparing it with different techniques for closure detection. According to the article, traditional methods for identifying the closure of hydraulic fracturing operations are based on assumptions that can conflict with one another, resulting in greatly varying approximations of closure pressure and duration. To address this issue, the article employs a set of diagnostic fracture injection tests that utilize the Step-Rate Injection Method for Fracture In-Situ Properties tool (SIMFIP). By directly observing wellbore deformation, the SIMFIP tool determines the minimum principal stress, while strain gauges monitor the opening and closing of fractures during multiple tests. The publicly accessible data are used to evaluate the accuracy of the new closure detection technique using CWT. The findings indicate that the CWT method aligns with measurements of deformation and can identify the impact of intricate closure events and pre-existing natural fractures. In conclusion, the article suggests that the CWT technique shows great potential as an alternative to traditional approaches for detecting closure pressure.

A Numerical Model for Pressure Analysis of a Well in Unconventional Fractured Reservoirs

Fractured reservoirs are highly heterogeneous in both matrix and fracture properties, which results in significant variations in well production. Assessing and quantifying the influence of fractures on fluid flow is essential for developing unconventional reservoirs. The complicated effects of fractures in unconventional fractured reservoirs on fluid flow highly depend on fracture geometry, fracture distribution, and fracture properties, which can be reflected in pressure transient testing. The biggest challenge lies in delineating the pre-existing natural fracture distribution pattern, density, azimuth, and connectivity. Using the advanced finite element method, this paper builds a finely characterized near-wellbore model to numerically simulate the pressure transient testing process in naturally fractured reservoirs and further evaluates fracture-related effects to obtain a more accurate solution. First, the numerical program is benchmarked by the analytical solutions and numerical results of Eclipse. Next, different fracture models with single fractures or fracture networks are set up to investigate the effects of fracture parameters numerically (e.g., fracture location, fracture dip angle, fracture spacing, the ratio of fracture permeability to matrix permeability, fracture network orientation, horizontal fracture distribution, etc.) on pressure transient behaviors in naturally fractured reservoirs. Velocity and pressure profiles are presented to visualize and analyze their effects, and new features in the flow regimes of the derivative plots of the bottom-hole pressure are identified and discussed. Finally, based on geological and geophysical data, including image logs, core descriptions, wireline logs, and seismic and well test data, a practical fractured model of the Dalwogan 2 well in the Surat basin is built, analyzed, and compared with homogenous and measured data. The results show significance in characterizing the complex fracture networks in near-wellbore models of unconventional fractured reservoirs.

Permeability evolution during pressure-controlled shear slip in saw-cut and natural granite fractures

Fluid injection into rock masses is involved during various subsurface engineering applications. However, elevated fluid pressure, induced by injection, can trigger shear slip(s) of pre-existing natural fractures, resulting in changes of the rock mass permeability and thus injectivity. However, the mechanism of slip-induced permeability variation, particularly when subjected to multiple slips, is still not fully understood. In this study, we performed laboratory experiments to investigate the fracture permeability evolution induced by shear slip in both saw-cut and natural fractures with rough surfaces. Our experiments show that compared to saw-cut fractures, natural fractures show much small effective stress when the slips induced by triggering fluid pressures, likely due to the much rougher surface of the natural fractures. For natural fractures, we observed that a critical shear displacement value in the relationship between permeability and accumulative shear displacement: the permeability of natural fractures initially increases, followed by a permeability decrease after the accumulative shear displacement reaches a critical shear displacement value. For the saw-cut fractures, there is no consistent change in the measured permeability versus the accumulative shear displacement, but the first slip event often induces the largest shear displacement and associated permeability changes. The produced gouge material suggests that rock surface damage occurs during multiple slips, although, unfortunately, our experiments did not allow quantitatively continuous monitoring of fracture surface property changes. Thus, we attribute the slip-induced permeability evolution to the interplay between permeability reductions, due to damages of fracture asperities, and permeability enhancements, caused by shear dilation, depending on the scale of the shear displacement.

Hydraulic fracture network propagation in a naturally fractured shale reservoir based on the “well factory” model

In different geological and engineering conditions, it is important to study the stress interference of multiple fractures and interaction of natural fractures in “well factory” fracturing to improve the complexity of fracture networks. For this purpose, a 2D, coupled stress-seepage-damage field cohesive model with random propagation of hydraulic fracture was developed, and a random function was used to simulate the natural fractures distribution in a real reservoir. Orthogonal test was designed to investigate the geological and engineering parameters impacting the evolution of zipper fracturing and modified zipper fracture networks. The results show that in naturally fractured reservoirs, hydraulic fracture can open natural fractures and promote the formation of complex fracture networks by combined, induced manner. Higher stress differences lead to simpler fracture networks and straighter hydraulic fracture propagation paths; When pre-existing natural fracture is longer, the propagation direction of hydraulic fracture is more likely to be paralleled with natural fracture; However, the stress shadow effect of multiple fractures may potentially lead to failure of some hydraulic fracture initiation. In addition, the fracture initiation sequence of multiple fractures has a significant effect on the evolution of the fracture networks. The results of the study have important significance for parameter optimization of well factory fracturing in naturally fractured reservoirs.

High-quality fracture network mapping using high frequency logging while drilling (LWD) data: MSEEL case study

The Marcellus Shale and Energy Environmental Laboratory (MSEEL) provides a comprehensive dataset and field tests that can be used to study the significance of preexisting natural fractures in different subsurface engineering problems such as the effectiveness of the stimulation of an unconventional reservoir, optimized geothermal fluids movement and integrity of the CO2 storage site. Conventionally natural fracture intensity is obtained using sonic and micro-resistivity imaging logs. However, these techniques significantly suffer from two major deficiencies: Human bias in log interpretation and extremely long interpretation time. These two deficiencies are well-recognized in the industry; however, no standard procedures exist to address them. In this study, a new automated machine learning workflow (AMLW) is introduced that uses the LWD high-resolution acceleration data along the horizontal laterals to predict the natural fracture intensities originally obtained using sonic and micro-resistivity imaging. The accuracy and robustness of the new workflow to predict the near wellbore fracture intensities are tested using both regression and classification approaches. Both the regression and classification approaches were able to predict the fracture intensities with high accuracy (average Mean Squared Error of 0.0085 for regression and average accuracy of 0.94 in the confusion matrix for classification). We have shown that only 10%–15% of the labeled resistivity image log is required for training and validation of the machine-learning model. The Automated workflow resulted in K-Neighbors Regressor and classifier algorithms as the best algorithms with a 52.74% and 139.3% improvement in comparison to the Gradient Boosting Regression algorithm (i.e. the fifth best algorithm).

Study of D-limonene as novel green hydraulic fracturing surfactant in shale gas reservoir

This study focuses on rock-fluid interaction during hydraulic fracturing in shale gas reservoir. Hydraulic fracturing is a well stimulation technique used to create fracture network in reservoirs by connecting the main planar hydraulic fracture with the pre-existing natural fracture. Hydraulic fracturing fluid additives such as surfactants are added into the hydraulic fracturing fluid system to enhance oil and gas productivity by assisting fluid recovery after fracturing. The main objective of this study is to evaluate the effectiveness and formation damage parameters of the proposed novel green surfactant as hydraulic fracturing fluid additive where commercial-chemical based surfactant was studied for comparison purpose. The green surfactant used was D-limonene whereas Sodium Alpha Olefin Sulfonate (AOS) was used as commercial-chemical based surfactant. Thermogravimetric analysis (TGA) was done to ensure the D-limonene can withstand the high reservoir temperature in which the D-limonene had inflection point and onset temperature of 410 °C and 380 °C respectively. Soaking test was then conducted where the shale samples were soaked in hydraulic fracturing fluid for seven days. The outcome of the soaking test was then studied in Scanning Electron Microscopy (SEM) and wettability analysis. The SEM test showed that the average pore size of the soaked shale samples were similar to the original shale sample which indicated minimal to no formation damage caused by the hydraulic fracturing fluid. Besides that, the contact angle test resulted in the distilled water and D-limonene forming a contact angle of 90° and 0° respectively on the shale samples. The AOS formed contact angles between 65° and 75° for the tested concentrations. From the results, the shale sample was found to be oil wet and showed a high affinity towards the D-limonene followed by AOS and distilled water. Higher affinity of the surfactants promoted the desorption of the hydraulic fracturing fluid from the shale surface.

Fracture development and inter-well interference for shale gas production from the Wufeng-Longmaxi Formation in a gentle syncline area of Weirong shale gas field, southern Sichuan, China

The Weirong shale gas field, located within a low-steep structural belt in southern Sichuan Basin, China, is characterized by gentle structural deformation. Production results have shown that inter-well interference, also known as fracture channeling, affects the productivity of shale gas wells by facilitating fluid flow between wells along pre-existing natural fractures. In this study, we used core observational data, scanning electron microscopy, and image logging analysis to determine the type, intensity, occurrence, and genetic mechanism of the natural fractures in the Upper Ordovician Wufeng-Silurian Longmaxi Formation. Attributes such as seismic coherence, AFE (fault-enhanced attribute), dip, and curvature were utilized to predict the macro and meso fault-fractures in the study area. We modeled the micro fault-fractures using the seismic and tracking algorithm to characterize the faults at multiple scales in the Weirong shale gas field, and then completed a comprehensive evaluation of the overall fracture development patterns with respect to the fracture channeling of neighboring shale gas wells. Results indicate that both horizontal and vertical structural fractures have been developed in the shale reservoir of the Wufeng-Longmaxi Formation in the Weirong shale gas field, although the horizontal fractures heavily outnumber the inclined ones. While a few high-conductivity macro and meso fractures display a NE-SW strike, abundant micro-faults have NE-SW and NWW-SEE strikes. Due to the pre-existing basement faults, stress fields and micro-amplitude structure, the NWW-SEE-trending micro fault-fractures are more active than those oriented in the NE-SW direction. Based on field observations, we conclude that regions with well-developed natural fault-fracture networks are more likely to have experienced fracture channeling between or within the platforms of well groups; and the NWW-SEE-trending micro fault-fractures generate more inter-well interference than the NE-SW-trending ones. Predicting the distribution and understanding the origin of the micro fault-fractures make it possible to prevent or mitigate the effects of fracture channeling during the drilling and artificial stimulation of shale gas wells.

Dynamic Shear Failure of Freeze-Thawed Tibet Hornfels Subjected to Multilevel Cyclic Shear (MLCS) Loads: Insights into Structural Dependent Failure Characteristics

Abstract Shear instability behavior is typical failure mode of rock mass in civil and mining engineering. Many attempts have been performed for rock joints or nonpersistent rock bridge under static shear conditions, yet the shear failure of rock mass subjected to cyclic or fatigue shear conditions is not well understood. Multilevel cyclic shear (MLCS) loading experiments were carried out on freeze-thawed hornfels to reveal the fracture and energy evolution characteristics using a self-special designed rock dynamic shear testing apparatus. The effect of the preexisting natural fracture on rock shear strength, deformation, energy dissipation, and shear failure pattern were experimentally investigated. The testing results show that aperture of open-mode fractures increases quickly, and this kind of natural fracture contributed a lot to rock failure. The evolution of stress hysteresis loop and its pattern are impacted by natural fracture, and it determines the damage accumulation. In addition, a damage evolution model was proposed to describe the damage evolution defined by the dissipated energy; the model can well describe the two-stage damage propagation for each cyclic stage and the entire cyclic loading process. Good agreement was found among the irreversible strain, energy dissipation, and failure morphology that are influenced by the preexisting natural fractures. It is suggested that the rock dynamic shear failure behaviors are rock structural dependent; the disturbed stress alters the energy dissipation and release characteristics.

A quantitative model to predict hydraulic fracture propagating across cemented natural fracture

A quantitative model is proposed to predict hydraulic fracture propagating across cemented natural fracture based on the numerical simulation and statistical regression. The cohesive zone method is employed to capture fracture initiation and growth, and the model combining rock deformation and fluid flow is established to simulate hydraulic fracture propagation with pre-existing natural fracture. The numerical model is solved by using finite element method, and verified against the analytical solution on the classical fracture problem. The investigation of influencing factors on hydraulic fracture propagation shows that the horizontal principal stress difference, approaching angle, cementing strength of natural fracture, injection rate and fluid viscosity codetermine whether hydraulic fracture propagates across natural fracture. After identification of these influencing factors, a series of numerical cases are conducted based on different combination of factor levels. Then the logistic regression method is employed to get the quantitative relationship between the crossing result and the factors, and the accuracy of regression equation is above 99%. The crossing curves are drawn to give the threshold of injection rate for varying other influencing factors. The potential applications include the usage of crossing criterion in the numerical modeling of fracture network propagation and the optimization of injection rate in the real field.