Xu, Feng (RIPED / CNODC) | Li, Xianbing (RIPED) | Gong, Yiwen (The Ohio State University) | Lei, Cheng (RIPED) | Li, Xiangling (RIPED) | Yu, Wei (The University of Texas at Austin / Texas A&M University) | Miao, Jijun (The University of Texas at Austin / SimTech LLC) | Ding, Yutao (CNODC)
Natural fractures are commonly observed in the unconventional reservoir. Production history indicates that natural fractures have been playing an important role in the oil and gas development progress by improving the permeability of the reservoir and increasing the well productivity. In addition, inappropriate development strategies result in the unreasonable single well oil rate, early water breakthrough, severe damages to the unconventional reservoir and overwhelming economic losses when the fracture properties and distributions are not well understood before the development. Hence, it is of great importance to propose a powerful and efficient workflow to describe the fracture distribution clearly, including building a 3D fracture model, performing history matching and forecasting productions of the unconventional reservoir. In this study, we present a powerful and practical workflow through using Fracflow software and EDFM (Embedded Discrete Fracture Model) to build the 3D DFN (Discrete Fracture Network) model. The main methodology used to perform the fracture modelling allows rigorously handling of both hydraulic fractures and natural fractures that can be identified in an unconventional reservoir. This modelling allows computing the real geometrical fracture attributes (mainly orientation and density) and the spatial distribution of fractures. Fracture conductivity values will be calibrated through a comparison of the Kh(permeability thickness) from the well test to the Kh model computed from the upscaling of the fracture model. The mentioned model above will be built by means of a stochastic simulation constrained by the results of the static and dynamic fracture characterization. In the reservoir simulation phase, EDFM processor combining commercial reservoir simulators is fully integrated to perform history matching and production performance forecast of the unconventional reservoir. With a new set of formulations used in EDFM, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. EDFM provides three kinds of NNC pairs, transmissibility factors, and the connections between fractures and wells. With the aid of the EDFM processor, we can obtain the number of additional grids, the properties of fracture grids, and the NNCs as the simulation input. From the proposed workflow, complex dynamic behaviors of natural fractures can be captured. This will further ensure the accuracy of DFMs and the efficiency offered by structured gridding. The practical workflow for the unconventional reservoir from modelling to simulation highlights the model constrained by the results of the static and dynamic fracture characterization, and the high efficiency to model discrete fractures through the revolutionary EDFM processor. Through this workflow, we can perform history matching effectively and simulate complex fractures including hydraulic fractures and naturally fractures. It potentially can be integrated into existing workflow for unconventional reservoirs for sensitivity analysis and production forecasting.
Almost simultaneously, advances were made in understanding both the processes within the source rock organic matter that accompany the generation and expulsion of hydrocarbons and in the acquisition, processing, and quantitative interpretation of 3D seismic data. In particular, as organic matter in shales in unconventional plays generates and expels hydrocarbons, porosity is formed in the organic matter and the organic matter becomes more dense and more brittle. As these changes are occurring at a micro-scale, extraction of hundreds of different attributes from a well-imaged 3D seismic volume has made it possible to observe changes at a macro-scale in seismic lines and horizons within that volume. Seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to calculate TOC, pore pressure, rigidity, and compressibility because these properties cause fundamental changes in how seismic waves travel through the rock.
Equally important, the escalation in computing power via methods such as machine learning, neural networks, and multivariate statistics has made it possible to interpret large amounts of data. All of these innovations have contributed to better identification of sweet spots within unconventional plays. Such sweet spots include areas with elevated TOC values, enhanced porosity, and zones that can be targeted for fracking.
One of the primary advantages of seismic data is that it provides information in those areas in between control points/wells. This information in turn helps operators to better select targets for wells and for landing zones. Carefully tied 3D seismic inversion and integration with petrophysical and rock data further allow for detailed characterization of unconventional reservoirs. The enhanced ability to identify the best potential drilling targets has significant economic implications in terms of risk reduction and improved chances to find economic prospects.
While 3D seismic data is being used routinely by numerous companies to predict the mechanical properties, density, and associated TOC of many formations, there is yet to be a direct link made between TOC loss, kerogen conversion, and the associated changes in rock properties. This work documents the importance of TOC loss during maturation and its effects on rock properties like porosity, density, brittleness, and how those advances coupled with the advances in quantitative interpretation of 3D seismic data are enabling the unconventional operators to predict location, thickness, landing zone, and sweet spots with appropriately acquired, processed, and interpreted 3D seismic. Meticulously calibrated 3D seismic inversion and integration with petrophysical and rock data permit detailed reservoir characterization of unconventional reservoirs.
Updated methods for the back calculation of original TOC have been developed using well logs, rock measurements, and 3D basin modeling to assist in locating and developing unconventional reservoirs. In addition, petrophysical measurements that reflect TOC and porosity and are related to fundamental properties controlling the seismic response can be extracted from the seismic reflection data. In turn, seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to estimate TOC, pore pressure, rigidity, and compressibility because these properties cause basic modifications in how seismic waves travel through the rock.
This study shows advancements in studies of: 1) TOC loss with increased thermal maturation, 2) how this loss affects the development of organic porosity, 3) how kerogen becomes denser, harder, and more brittle with increasing maturity, and 4) how recent developments in quantitative interpretation workflows for 3D seismic data facilitate estimation of TOC and determination of rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density. Further integration of geochemical, geomechanical, and geophysical technologies and measurements will provide improved estimates of present-day TOC that can in turn be extended to relative maturity and percent conversion.
Examples provided in this work illustrate prediction of present-day TOC, porosity, density, and mechanical properties extracted from high fidelity pre-stack inversion. Pre-stack inversion along with machine learning can be used to predict rock properties such as porosity, TOC, organic matter quality, rigidity, and pressure and to correlate those properties back to well productivity for improved execution. Relating present TOC estimated from seismic to TOC loss and kerogen property changes with increasing maturity is possible by combining the results of these technologies.
Though analysis and inversion of painstakingly acquired modern 3D seismic data is capable of estimating porosity, TOC, matrix strength, and pore pressure, the latest work on rock property changes as hydrocarbons mature and are expelled isn't typically addressed in most studies. Increasing communication between disciplines might improve estimation of these properties and extend the capability to assess the extent of TOC loss during maturation and the porosity increases that accompany it. This ability is especially important in the intra-well regions where the potential of 3D seismic to extend data between control points enables better reserve estimates and high grading of acreage. After carefully calibrating a quantitative 3D seismic interpretation with a 3D basin modeling analysis of the source rock potential and maturity, an operator is better prepared to high grade acreage and attain the most economic development of unconventional resources.
The escalation in computing power means there are hundreds of different attributes that can be extracted or calculated from a well-imaged 3D seismic volume. Using quantitative calibration of fundamental geochemical measurements such as TOC, pyrolysis, and petrographic measurements of vitrinite reflectance that yield the quantity, quality, and maturity of organic matter in combination with well log and seismic data creates a model for identifying sweet spots and the areas in the target formation that exhibit high TOC, high porosity, and elevated brittleness. Further integration and calibration of changes occurring at the micro-level in organic matter in unconventional plays with their impact on the signatures of data at the macro-level can provide information on the types of hydrocarbons most likely to be found in these sweet spots as well as identifying which zone(s) in the target formation are most likely to be amenable to fracking. Used together, the advances outlined here result in a technological evolution that could have a substantial impact on: 1) the approach to and 2) the economics of the exploration and production of unconventional plays.
Park, Jaeyoung (Texas A&M University) | Iino, Atsushi (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | Bi, Jackson (Anadarko Petroleum Corporation) | Sankaran, Sathish (Anadarko Petroleum Corporation)
The objective of this study is to develop a workflow to rapidly simulate injection and production phases of hydraulically fractured shale wells by (a) incorporating fracture propagation in flow simulators using a simplified physical model for pressure-dependent fracture conductivity and fracture pore volume (b) developing a hybrid Fast Marching Method (FMM) and 3D Finite Difference(FD) model for efficient coupled simulation and (c) automating the entire workflow for rapid analysis in a single simulator domain.
Pressure-dependent fracture transmissibility and pore volume multiplier models are assigned to predefined potential hydraulic fracture paths to mimic geomechanical behavior of fractures (i.e. opening and closure). The multipliers are based on empirical equations (e.g., Barton-Bandis model) and theoretical models (e.g., linear elastic fracture mechanics and cubic law). The FMM-based simulation transforms an original 3D reservoir model into an equivalent 1D simulation grid leading to orders of magnitude faster computation and is utilized to efficiently history-match field production and pressure data. A population-based history matching algorithm was used to minimize data misfit and quantify uncertainties in tuning parameters.
We demonstrate the effectiveness and efficiency of the proposed method using synthetic and field examples. First, we validated our proposed simplified fracture propagation model with a comprehensive coupled fluid flow and geomechanical simulator, ABAQUS. The results showed close agreement in both injection pressure response and fracture geometry. Next, the method was applied to a field case to history-match injection pressure and production data. Fracture geometry and properties were inferred from the injection phase and are input to the production phase modeling. After history matching, the misfit and uncertainty ranges in reservoir and fracture properties were substantially reduced.
The proposed workflow enables rapid analyses of hydraulically fractured wells and does not require computationally demanding geomechanical simulations to generate fracture geometry and properties. The FMM-based simulation further improves computational efficiency and allows us to automate the workflow using population-based history matching algorithms to quantify and assess parameter uncertainty.
Klie, Hector (DeepCast.ai) | Klie, Arturo (DeepCast.ai) | Rodriguez, Adolfo (OpenSim Technology) | Monteagudo, Jorge (OpenSim Technology) | Primera, Alejandro (Primera Resources) | Quesada, Maria (Primera Resources)
The Vaca Muerta formation in Argentina is emerging as one of the most promising resources of shale oil/gas plays in the world. At the current well drilling pace, challenges in streamlining data acquisition, production analysis and forecasting for executing timely and reliable reserves and resource estimations will be an overarching theme in the forthcoming years. In this work, we demonstrate that field operation decision cycles can be improved by establishing a workflow that automatically integrates the gathering of reservoir and production data with fast forecasting AI models.
We created a data platform that regularly extracts geological, drilling, completion and production data from multiple open data sources in Argentina. Data cleansing and consolidation are done via the integration of fast cross-platform database services and natural language processing algorithms. A set of AI algorithms adapted to best capture engineering judgment are employed for identifying multiple flow regimes and selecting the most suitable decline curve models to perform production forecasting and EUR estimation. Based on conceptual models generated from minimum available data, a coupled flow-geomechanics simulator is used to forecast production in other field areas where no well information is available. New data is assimilated as it becomes available improving the reliability of the fast forecasting algorithm.
In a matter of minutes, we are able to achieve high forecasting accuracy and reserves estimation in the Vaca Muerta formation for over eight hundred wells. This workflow can be executed on a regular basis or as soon as new data becomes available. A moderate number of high-fidelity simulations based on coupled flow and geomechanics allows for inferring production scenarios where there is an absence of data capturing space and time. With this approach, engineers and managers are able to quickly examine a feasible set of viable in-fill scenarios. The autonomous integration of data and proper combination of AI approaches with high-resolution physics-based models enable opportunities to reduce operational costs and improving production efficiencies.
The integration of physics-based simulations with AI as a cost/effective workflow on a business relevant shale formation such as Vaca Muerta seems to be lacking in current literature. With the proposed solution, engineers should be able to focus more on business strategy rather than on manually performing time-consuming data wrangling and modeling tasks.
Economic hydrocarbon production from organic rich shale has been made feasible by advances in horizontal drilling and hydraulic fracturing. Proppants are pumped to keep the fractures open and provide a high conductive path from the reservoir to the wellbore. Effects of proppant size, proppant crushing, fines migration, rock mineralogy and fluid chemistry on the long-term fracture conductivity have been studied experimentally in detail by Mittal (2017, 2018). This study further investigates the impact of proppant concentration, size and presence of different volcanic ashes on fracture conductivity along with different conductivity impairment mechanisms including proppant crushing, embedment and diagenesis under simulated reservoir conditions.
Experiments have been conducted by varying the proppant concentration of 60/100 mesh Ottawa sand from 2 lb/ft2 to 4 lb/ft2. The proppant pack was placed between metal platens and subjected to axial load of 5000 psi and temperature of 250 °F. Proppant pack conductivity was then measured by flowing 3% NaCl brine for periods of 7-15 days. We observed a sharp decline in permeability, with almost 98% decline within 3 days with low concentration compared to only 60% decline in permeability with higher concentration of proppant. Particle size analysis reveals overall 5% higher percentage crushing at lower proppant concentration, suggesting major crushing occurs at the platen interfaces which reduces with increased proppant pack concentration.
Presence of volcanics in the major shale plays like Eagle Ford and Vaca Muerta has been reported in literature. To simulate similar environment and study the impact of diagenesis on fracture conductivity, experiments have been conducted by flowing high pH (~10) brine through the proppant pack mixed with volcanics like obsidian and basalt and placing the proppant between Eagle Ford shale platens. Experiments were conducted with 20/40 Ottawa sand mixed with obsidian and 60/100 mesh Ottawa sand mixed with basalt. We observed a sharper decline in permeability with 60/100 sand as compared to 20/40 sand in the first two days. However, the permeability for both the proppant sizes continues to decline with a difference of an order of magnitude even after 30 days. SEM images shows significant particle crushing, embedment and diagenetic growth on the shale surface and verify that these factors are responsible for permeability decline. To further understand the impact of proppant size on permeability, dry crush tests have been conducted on 20/40 and 60/100 Ottawa sand by varying compaction pressure from 1500 psi to 3000 psi and 5000 psi. We observed that 60/100 mesh sand undergo overall higher compaction and crushing compared to 20/40 mesh sand at each compaction pressure.
Vaca Muerta shale is among the most promising unconventional plays outside of North America. Like other shale plays, it is developed using multistage hydraulic fracturing technology. In this experiment, dual microseismic arrays were deployed during stimulation to monitor fracture geometry. Beyond location of events, moment tensor inversions were performed on three horizontal wells. Fault plane solutions were derived based on the double-couple model from moment tensor results. Then the fault plane solutions were used as inputs for calculating stress field by minimizing the misfit between regional stress field and a cluster of fault plane solutions. The stress inversion results show that the stress direction derived from each stage is consistent with regional tectonic stress direction. The post-stimulation stress regimes vary between strike-slip and reverse faulting, which indicates stress shadowing effects among neighbor stages. The uncertainties are estimated using the statistical bootstrapping method. In addition, the stress inversion results were compared with ISIP (Instantaneous Shut-In Pressure) data and b-values and show some level of consistency.
Vaca Muerta Shale in the Neuquen Basin of central west Argentina is a massive unconventional resource play outside of North America. The same technology of horizontal drilling combined with multi-stage hydraulic fracturing are being implemented to extract hydrocarbon from the tight organic rich shale formation. The quality of rock is comparable to the major plays in North America such as Marcellus, Eagle Ford and Bakken (Cataldo et al. 2016). Argentina is estimated to have the world's second largest shale gas reserve according to US Energy Information Administration. Production from Vaca Muerta is rapidly increasing, with a prediction up to 1 million BOE/D in 15 years (Donnelly 2018).
Microseismic has evolved into a mainstream monitoring technique for hydraulic fracturing. The advantage from microseismic is the 4D coverage in space and time. However, the majority of microseismic monitoring projects only uses the location information to define stimulated rock volume. Going beyond “dots in the box” becomes an urgent need for the microseismic community to provide better information to influence the operational design (Tan et al. 2014; Zhang et al. 2018).
Tomassini, Federico Gonzalez (YPF SA) | Smith, Langhorne (Taury) (SmithStrata) | Rodriguez, Maria Gimena (YPF SA) | Kietzmann, Diego (University of Buenos Aires - CONICET) | Jausoro, Ignacio (YPF Tecnología SA [Y-TEC]) | Floridia, Maria Alejandra (YPF Tecnología SA [Y-TEC]) | Cipollone, Mariano (YPF Tecnología SA [Y-TEC]) | Caneiro, Alberto (YPF Tecnología SA [Y-TEC]) | Epele, Bernarda (YPF Tecnología SA [Y-TEC]) | Santillan, Nicolas (YPF Tecnología SA [Y-TEC]) | Medina, Federico (YPF Tecnología SA [Y-TEC]) | Sagasti, Guillermina (YPF SA)
The objective of this work is to present the pore types and their relationship to the main core facies from the Vaca Muerta Formation, Neuquén Basin, Argentina. With an in-house methodology for focused Ion Beam scanning electron microscope (SEM) images and petrographic analysis, a linked to increase the understanding of the pore systems, mineralogy, diagenetic features, grain types and facies variations is carried out. Long continuous cores from two wells were described in detail by standard facies analysis and SEM for semi-quantitatively estimating total porosity, relative abundance of pore types and pore sizes, mineralogy, relative abundance of kerogen and migrated bitumen, type and origin of different clays, and diagenetic quartz abundance among other features. The SEM porosity, organic matter content and mineral distribution correlates favorably with independent measurements obtained by other labs methods. The findings were linked to the core descriptions and the regional sequence stratigraphic framework to predict best reservoir facies. This prediction is done with the production results for each horizontal well in the different landing zones. Finally, the understanding of the pore system can be used to define the best areas and intervals where horizontal wells can be geosteered during the development stage of a block.
The Tithonian-Valanginian (Upper Jurassic-Lower Cretaceous) Vaca Muerta Formation is the main source rock of the Neuquén Basin (Figure 1). The Vaca Muerta Fm. is a lower slope and basinal facies equivalent to the updip Quintuco and Loma Montosa Formations. This formation is a very appealing target for unconventional development due to its vast lateral extent, great thickness (up to 500 m – 1640 ft), relatively high values of total organic carbon (TOC 2-10 %), thermal maturity (oil to dry gas windows), mineralogical composition (less than 30% clay), overpressure and relatively simple structural setting. The study area is located in the center of the Neuquén Basin (Figure 1), north of the Huincul high and mainly in the Añelo depocenter where major activity is taking place. More than 600 horizontal wells have been drilled in the basin in different landing zones resulting in different hydrocarbon production. The EIA (2013) estimated that the technically recoverable resources estimated for this formation are in the order of 300 Tcf of gas and 16 Bbbl of oil and these numbers may be low.
Geri, Mohammed Ba (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Ofori, Bruce (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Sherif, Huosameddin (Missouri University of Science and Technology)
Recent studies have presented successful case studies of using HVFR fluids in the field. Reported cost reductions from using fewer chemicals and less equipment on the relatively small Marcellus pads when replacing linear gel fluid systems by HVFR. The investigation provided a screening guideline of utilizing HVFRs in terms of its viscosity and concentration. The study notes that in field application the average concentration of HVFRs is 2.75 gpt (gal per 1,000 gal)
Three different scenarios were selected to study fluid type effect using 3D pseudo simulator; as a first scenario; fracture dimensions as a second scenario; the last scenario was proppant type. The first scenario consists of two cases: utilizing HVFR-B as new fracture fluid in 20% of produced water was investigated in scenario I (base case). Comparison between HVFR and linear gel in the Middle Bakken was investigated in Case II of the first scenario. At the second scenario, fracture half-length was studied. Proppant distribution impact by using HVFR in Bakken formation was analyzed as the third scenario. The final scenario investigated the pumping flow rate influence on proppant transport of using HVFR. The concentration of HVFR-B was 3 gpt and the proppant size was 30/50 mesh. The treatment schedule of this project consists of six stages. The proppant concentration was increased gradually from 0.5 ppt to 6 ppt at the later stage.
In the case of using HVFR-B the fracture half-length was approximately 1300 ft while using linear gel created smaller fracture half-length. In contrast, using linear gel makes the fracture growth increase rapidly up to 290 ft as showed. To conclude, using HVFR-B created high fracture length with less fracture height than linear gel. Additionally, in using HVFR-B, the average fracture height was approximately 205 ft while using linear gel created increasing of the fracture growth rapidly up to 360 ft which represent around 43% increasing of the fracture height. In studying the impact of fracture half-length on proppant transport, increasing fracture half-length from 250 ft to 750 ft leads to the fracture growth rapidly up to 205 ft
Studying the impact of proppant size effect on proppant transport, we observed changing fracture conductivity across fracture half-length. Thus, the fracture height increasing with decreasing proppant mesh size. Fracture height increased from 193 ft to 206 ft by changing proppant mesh size from 20/40 to 40/70 mesh. With flow rate impact on proppant transport, it was observed that, the fracture height increases by increasing the pump rate. Utilizing HVFR-B in the fracture treatment provides higher absolute open flow rate (AOF) which is around 2000 BPD. On the other hand, the outcomes of using linear gel has less AOF that about 1600 BPD. Also, Increasing the Xf and proppant mesh size leads to increase the AOF.
This project describes comparison of the successful implementation of utilizing HVFR as an alternative fracturing system to linear gel.
The Meramec Formation in the STACK play has moved to full field development and multiple wells are put on production in a relatively short time. Our results provide asset teams with key geologic, completions, and operations characteristics and their relative contribution to well performance. Depending on the desired economic metric (NPV or ROR), the drawdown strategy and the magnitude of intra-well interference (fracture to fracture) can be optimized. For instance, if the objective is to maximize rate of return, then tighter fracture spacing may be accepted. Results provide guidance to optimal design parameters and operational strategies in the Meramec Formation.
Optimal cluster spacing has eluded reservoir and completions engineers since the inception of multi-stage hydraulic fracturing. Very small cluster spacing could result in fracture to fracture (intra-well) interference and higher completions cost, whereas very large cluster spacing could lead to inefficient resource recovery which is detrimental to the economics of the well.
This study interrogates the relative contribution of rock matrix, completions, and operational characteristics, vis-a-vis short and long term well performance in tight oil reservoirs. Those characteristics include drawdown strategy, cluster spacing, pressure dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model which will be used to history match a well from the Meramec Formation.
The static model covers an area of 640 acres that encompasses a multi-stage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than two years of continuous production without being disturbed by offset operations. History match was obtained to three-phase production and flowing bottom-hole pressure. By utilizing element of symmetry, numerical models were created to investigate the effect of fractures interference on short- and long-term oil recovery and producing gas-oil ratio.
Observations from diagnostics such as offset pressure gauges, micro-seismic, fiber optics, and radioactive tracers can provide critical insights into optimal fracture spacing. However, those observations remain incomplete without proper integration with physics-based models to predict well performance and optimize fracture spacing.
Findings suggest that drawdown strategy (aggressive versus conservative) is more impactful to short term oil productivity than fracture spacing. Drawdown strategy is even more impactful on short-term oil recovery than a 20% error in porosity, or water saturation. The profile of producing gas-oil ratio depends on fracture spacing and has been interpreted in the context of linear flow theory.
Water and gas permeability of fractures with or without proppants under in situ effective stress conditions is a key input parameter for numerical modelling of Stimulated Rock Volume (SRV) and optimization of proppants recipe used in hydraulic stimulation jobs for gas/oil shale reservoirs. This paper presents the experimental results of fracture permeability tests carried out on the Vaca Muerta shale, with and without proppants. Permeability tests are carried out according to a specific protocol simulating the change of in situ effective stress due to production. After creating a fracture in shear mode in the triaxial cell, the gas permeability was measured twice with a measurement of the water permeability between. Subsequently, the fracture was filled with the same proppants as used in the field. The mechanical closure and change of hydraulic opening of the fracture with different concentrations of proppants were then measured under cyclical effective stress. The evolution of fracture permeability is then compared with the mechanical closure recorded by an extensometer. This experiment is used to investigate the effect of proppant concentration on permeability evolution under varying effective stress. The experimental results presented in this paper can be used as input data for numerical modelling of fractured shale gas reservoirs and for optimization of proppant concentration in hydraulic stimulation jobs.
The potential of gas production is first and foremost determined by geochemical and petrophysical factors such as total organic carbon content, thermal maturity, porosity and permeability. However, the productivity is strongly dependent on the fracture network's connectivity and conductivity (including both hydraulic fractures and activated natural fractures) since the shale matrix has extremely low permeability. Numerous geomechanical parameters of shale control the hydraulic quality of stimulated reservoir volume (SRV) created by hydraulic stimulation: elasticity and its variability, strength with regards to tensile and shear failure as well as fracture propagation, filling material of natural fractures/joints and the permeability before and after stimulation (Su K et al. 2014).