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Summary Shear slip of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear slip by injection have not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford Shale sample having a single fracture (tensile fracture) was used to perform a laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, shear slip was induced on the fracture at near critical stress state by injecting pressurized brine water [7% potassium chloride (KCl)]. Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate), and AE signals (hits, events) were all recorded. The data were then used to characterize the fully coupled seismo-hydromechanical response of the shale fracture during shearing. Results show that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic-slip interval corresponding to a rapid fracture slip and a large stress drop. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Before this seismic interval, an aseismic-slip interval was evident during the tests, where the fracture slip, associated stress relaxation, and permeability increase were limited. The test results and analyses demonstrate the role of shear slip in permeability enhancement and induced seismicity by hydraulic stimulation for unconventional shale reservoirs. Introduction Shear slip of pre-existing fractures has long been recognized as a major permeability creation and microseismicity mechanism of reservoir stimulation (e.g., Pine and Batchelor 1984; Mayerhofer et al. 1997; Rutledge et al. 2004; Zoback et al. 2012).

Abstract Locations and source mechanisms of microseismic events are very crucial for understanding the fracturing behavior and evolution of stress fields within the reservoir and hence facilitates the detection of hydraulic fracture growth and estimation of the stimulated reservoir volume (SRV). In the classic workflow, there are two main methods for locating microseismic events with a calibrated fixed velocity model: grid search and linear inversion. The grid search is very stable; can find a global minimum and does not need initial event locations. However, it is computationally intensive and its resolution depends on the grid size, hence, it is not suitable for real-time monitoring. On the other hand, although the linear inversion method is quite fast, the inversion may be pushed into a local minimum by thin shale layers and large velocity contrasts leading to false locations. The source mechanisms of the located events, which provide information about the magnitudes, modes and orientations of the fractures, are obtained through moment tensor inversion of the recorded waveforms. In this paper, we propose a deep neural network approach to solve the above challenges, in real-time, and increase the efficiency and accuracy of location and moment tensor inversion of microseismic events, induced during hydraulic fracturing. Location of microseismic events was considered as a multi-dimensional and non-linear regression problem and a multi-layer two-dimensional (2D) convolutional neural network (CNN) was designed to perform the inversion. The source mechanisms of the microseismic events were inverted using a multi-head one-dimensional (1D) CNN. The neural networks were trained using synthetic microseismic events with low signal to noise ratio (SNR) to imitate field data. The overall results indicate that both the 2D CNN and 1D CNN models are capable of learning the relationship between the events locations and source mechanisms and the waveform data to a high degree of precision compared to classical methods. Both the event location and source mechanism errors are less than few percent. Deep learning offers a number of benefits for automated and real-time microseismic event location and moment tensor inversion, including least preprocessing, continuous improvement in performance as more training data is obtained, as well as low computational cost.

Abstract Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.

Shear reactivation of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. However, the mechanisms of permeability enhancement contributed by fracture shear slip are still poorly understood, and the laboratory experiments on shale fractures are insufficient. In this work, injection-induced shear tests were conducted on two reservoir shale samples (from the depth >10,000 ft.) each having a single rough fracture to characterize permeability evolution during fracture shear slip. In the tests, remarkable enhancement of flow rate/permeability have been achieved on both samples through fracture shear slip induced by elevating injection pressure. It is shown that ∼100 times increase in flow rate was induced by a ∼0.1 mm scale of shear slip on the two cylindrical shale samples (with ∼38 mm diameter). The permeability enhancement was retained on the sheared samples even with the decline of fluid pressure. This means that the permeability increase by fracture shear slip may be permanent. In addition, significant stress drops were induced by fracture shear slip in both tests, resulting in further fracture aperture/permeability enhancement. In one sample, a new fracture plane was formed during the shear slip of the original pre-existing fracture, which may help generate an interconnected fracture network. Therefore, dilatant shear slip, stress drop, and the new fractures formation are important and often integral mechanisms of permeability enhancement contributed by pre-existing fractures during shale reservoir stimulation. The results improve the understanding of shear slip in enhancing permeability of shale fractures, and would help engineer solutions for maintaining these fractures open, reducing costs (proppant/water and additive cost savings).

ABSTRACT In this study, we evaluate the potential significance of wellbore orientation and effective-stress-dependent fracture permeability on shale gas production. To do this, we modeled production from the MSEEL MIP-3H gas well using a simple reducedorder- physics discrete-fracture-network (DFN) reservoir model. Parameters for this model were obtained from site data and laboratory triaxial direct-shear tests. Stress-dependent fracture permeability parameters used a scalable exponential decay function that was fitted to the laboratory measurements. Production was then modeled using a modified transient formation linear gas flow equation. Our results indicate that stress-induced fracture closure can cause significant cumulative production loss in certain scenarios, but not in others. When fracture closure is important, aggressive pressure drawdown can rapidly close the fractures and be detrimental to reservoir performance. Furthermore, the orientation of a horizontal well could be optimized for improved recovery by accounting for both the tectonic stresses and natural fractures. Our results are part of a greater effort to identify production strategies that could help to achieve a higher cumulative shale gas production. 1. INTRODUCTION Fracture networks have long been attributed as a key factor for the economic hydrocarbon production from low-porosity, low-permeability shale formations because they provide primary fluid flow pathways for improved reservoir performance. This network is comprised of artificially induced hydraulic-fractures and natural fractures, given that the fracking treatment activates natural fractures based on microseismic observations (Rutledge and Phillips, 2003). Therefore, studies have been conducted to improve our understanding of the fracture network in the subsurface. These studies include, but are not limited to, natural fracture (NF) characterization (Gale et al., 2003), hydraulic fracturing (HF) optimization (Warpinski et al., 2009), and the HFNF interactions (Blanton, 1986; Wu and Olson, 2016). The deliverability of a naturally fractured shale reservoir strongly depends on the effective stress of the fractures. This is because the fractures function as the primary flow paths and their hydromechanical properties are highly susceptible to stress changes. Experiments have shown that the mechanical aperture of a single fracture in various lithologies can change over an order of magnitude when the effective normal stresses varies from 0 to ∼40 MPa (Bandis et al., 1983). Theoretical linear-elastic calculations also indicate that stress-induced closure is more profound for fractures with small aspect ratios (Jaeger et al., 2007). Furthermore, mathematical models have been developed to link fracture stiffness to the hydraulic properties (Pyrak-Nolte and Nolte, 2016).

Abstract For hydraulic fracturing in unconventional reservoirs, propped volume is the key to predicting total production. Microseismic analysis is frequently performed to detect fracture extension. Recently, microseismic analysis was utilized for various objectives. Though several methods of estimating proppant distribution are currently used, including tracers and core analysis, it is important to investigate whether microseismic analysis can discriminate proppant injection in order to cross-check and decrease the uncertainty of proppant distribution. To estimate the propped fracture distribution, accurate microseismic processing is important. In this study, indications of microseismic events caused by proppant injection were interpreted by accurate microseismic processing and the waveform-similarity clustering of microseismicity in the Horn River shale gas field. We analyzed a certain hydraulic fracturing stage of zipper fracturing. In this stage, hydraulic fracturing was carried out over 7000 seconds. The first proppant injection started 1000 seconds after starting water injection and continued for 2500 seconds. Next, larger proppant was injected after termination of the first proppant injection and continued for 3500 seconds. Microseismic data was acquired using 36 downhole arrays of 3C geophones in a vertical section of two horizontal wells. Microseismic events were located by focusing P-waves, because, in this field, there is high uncertainty in picking direct S-waves. After that, we classified microseismic events using waveform similarity clustering by cross correlation between each microseismic event in the P-waves and S-waves of the each microseismic data. Microseismic hypocenters were distributed in a bi-wing pattern from the perforation location. They were concentrated more on the southwest side than the northeast side. Sparse distribution in the northeast side could be caused by existing fractures from the neighboring well treatment. In a time-series histogram of microseismic event frequency, the events are concentrated at the start of water injection and second proppant injection. In a time-distance plot, a linear feature was detected which implies initial fracture opening. Applying the clustering procedure, two clusters were detected which include events that mainly occurred at the start of water injection. These events are located close to each other and have high waveform similarities, which implies that they have the same source mechanism, namely, initial fracture opening. Two other clusters were also detected that include events which only occurred at the start of the second proppant injection. These events were also located close to each other. From net pressure analysis, proppant screenout did not occur. Therefore, the events in the latter clusters are interpreted to have been caused by proppant injection and their hypocentres could represent proppant distribution. Although further investigation, including fracture propagation simulation, is required and only a few events are interpreted as events caused by proppant injection, this approach should help to estimate the distribution of propped fractures and the total propped volume.

Abstract Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the in-situ stress field inside and around the stimulated reservoir volume, due to both creation of new fractures and fluid leakoff into the surrounding rock matrix. The analysis of spatiotemporal dynamics of fluid-induced seismicity can reveal important characteristics of the hydraulic fracturing process. With the knowledge of treatment data, it can be used in conjunction with the reservoir geomechanical theories in hydraulic fracture growth to investigate the fracture geometry and fluid-rock interactions. By applying these theories to a real microseismic dataset, two types of triggering front expansion patterns are evident. With the presence of a dominant hydraulic fracture, the radius of the triggering front expands linearly with time. Moreover, the microseismic event cloud forms a planar shape with low opening angles (failed by shear), indicating fracture slippages around the major hydraulic fracture. On the other hand, in the case of a complex fracture network with the absence of any major hyfraulic fracture, the triggering front grows non-linearly with time. This scenario can be treated as equivalent to a diffusion model and the microseismic events exhibit a higher fracture of tensile components (either opening or closing) and an equidimensional event cloud. In this study, two stages were analyzed and the derived fracture widths and fluid-loss coeffcients fall into a realistic range of general observations in the context of these two theories.