Properties Of Shale Research Articles

Coupling grid nanoindentation and surface chemical analysis to infer the mechanical properties of shale mineral phases

Shale is a low-permeability, multi-phase, and multi-scale composite material with intrinsic heterogeneity in micro-texture and mineralogical composition. In this paper, relationships between the microscale texture and constituent phases of shale were investigated using SEM (scanning electron microscopy)/BSE (backscatter electron imaging)-EDS (energy-dispersive x-ray spectroscopy) methods, together with grid nanoindentation experiments. The mechanical properties of the constituent phases of the carbonate-rich Longmaxi shale samples were extracted based on the spatial distribution of mineral phases and the indentation interaction volume. We analyze the effects of particle size on the interpreted mechanical properties and establish a characteristic length scale based on a probabilistic analysis. The identified characteristic length for extracting the mechanical properties of constituent mineral phases from the grid nanoindentation technique is about 5.8–11.7 μm, i.e., up to 10 times greater than that proposed in prior research. A multi-scale mechanical model was established with considerations of a self-consistent scheme for granular morphology to link the microscopic characteristics with the multi-scale mechanical properties of shales. The modeling results show that the stiffness and the strength of the homogenized nano-porous illite/quartz aggregates in Longmaxi shale can be assessed from the nano-scale mechanical properties of the mineral phases and the nano-scale porosity. This study paves the way to accessing the mechanical properties of the constituent phases of composite materials based on the properties of their building blocks and provides extensive insights into their complex mechanical behavior, representing a major step towards developing reliable multi-scale models for engineering applications.

Estimating hardness and Young's modulus of shale using drill cuttings: Implications for hydraulic fracturing in shale gas reservoir development

Shale formations are widely prevalent in the oil and gas industry as potential hydrocarbon reservoirs. The hardness and Young's modulus of shale significantly impact the success of hydraulic fracturing operations in shale gas reservoir development. The unavailability of standard-sized core samples (length to diameter ratio ∼2.5) makes it challenging to determine the mechanical properties of shale in the laboratory. This study investigates techniques for estimating hardness and Young's modulus using drill cuttings. The microhardness was measured on shale cuttings of ∼1 mm in size using a micro indenter. Young's modulus was measured at the macro-scale using a uniaxial compression test on a 25 mm diameter core sample. The relationship between microhardness and Young's modulus established for Longmaxi (China) and Ice-Box (Western Canada) shales was applied to another shale (e.g., Sembar Shale of Pakistan), for which no core samples were available. The measured mineralogy of the studied shales provides a common base for the comparison of microhardness and Young's modulus using isotropic and anisotropic theoretical models. A positive correlation was observed between Young's modulus and microhardness for the three shales tested in this study. Although the scale of measurement/assessment is different, the theoretical models show an insignificant impact of the scale range (micro (mm) to macro (cm)) on Young's modulus, microhardness, and brittleness.

Upscaling the creep behavior of clay-rich and quartz-rich shales from nanoindentation measurements: Application to the Wufeng-Longmaxi shale, China

Creep of shale controls the stability of fault gouge in sedimentary rocks, aseismic deformation in the upper crust, and several engineering operations, such as proppant embedment, reservoir subsidence, and wellbore stability during unconventional shale gas exploitation. However, measuring the creep properties of shale is challenging due to the multi-scale structure of this rock. Here, our goal is to assess how creep parameters measured at the core sample scale depend on those measured at the nanoscale in shales. We selected three clay-rich and quartz-rich shale samples and conducted a series of experiments on shale samples at two scales: nanoindentation creep measurements on thin sections, and uniaxial creep tests on core samples. The creep parameters, including creep displacement (Δh), indentation creep (CIT), creep strain rate sensitivity (m), contact creep modulus (C), and viscoelastic parameters (E1, E2, η1, and η2) of the Burgers' model, were calculated by fitting the nanoindentation creep data of each single-phase component of shale matrix. From these data, we upscale the creep parameters (E1, E2, and C) of shale matrix to those of the bulk shale. Upscaled E2 and C values based on the Mori-Tanaka scheme are found to be relatively close to those measured in previous microindentation study on Longmaxi shale and are consistent with our measurements in uniaxial creep tests on core samples of clay-rich shale and quartz-rich shale. The upscaling value of the elastic parameters, E1, is almost twice larger than the results from uniaxial creep test. We interpret this difference as due to low elastic stiffness along grain contacts of the shale that nanoindentation measurements underestimate. Our results show a consistency of some creep parameters upscaled from nanoindentation data and those measured at a macroscopic scale on core samples.

Study on creep mechanical properties of carbonaceous shale under dry-wet cycle

The creep mechanical properties of rock under dry-wet cycles are of great significance for studying the long-term aging stability of engineering rock and soil. In the past, there were few studies in this area, and most of the dry-wet cycle tests on rock samples did not conform to the actual stress state of the rock. In view of the shortcomings of these studies, this paper innovatively carried out the dry-wet cycle test of the rock under the continuous state of the stress field, and studied its mechanical properties. The specific method is to take carbonaceous shale as the research object, and use the soft rock shear rheological test system independently developed by our research group to carry out the shear creep test of carbonaceous shale under the action of dry-wet cycle. The test results show that the creep full-time curves of carbonaceous shale under different dry-wet cycles show a step-shaped curve shape. The dry-wet cycle has a significant effect on the deformation characteristics of carbonaceous shale. With the increase of the number of dry-wet cycles, the instantaneous strain of the rock gradually increases, the instantaneous shear modulus decreases from 596.650 MPa at 0 times to 365.199 MPa at 12 times, and the attenuation rate reaches 38.79%. The creep strain and cumulative creep strain become larger, the stress required for accelerated creep decreases from 3.29 MPa to 2.75 MPa, and the accelerated creep time in the third stage increases from 11.892 h to 5.316 h, and the creep effect is more significant. The long-term strength of carbonaceous shale decreases from 3.05 MPa to 2.49 MPa, and the decrease increases with the increase of dry-wet cycles. The more the number of dry-wet cycles, the smaller the undulation of the shear failure section of the carbonaceous shale, and the smoother the surface. The research results have important guiding significance for the long-term aging stability analysis of engineering rock and soil mass subjected to repeated dry-wet cycles.

Wettability and fluid characterization in shale based on T1/T2 variations in solvent extraction experiments

Rock wettability and pore fluid properties are critical parameters for evaluating shale reservoirs, enhancing oil recovery, sequestering waste, and storing energy. Multiple petrophysical and geochemical experiments are routinely used to characterize these properties of shales. Two-dimensional nuclear magnetic resonance (NMR)-based shale evaluation methods usually rely on T1/T2 difference in various fluids. However, T1/T2 value is inadequate for petrophysical characterization due to the similar T1/T2 value of different hydrogen types in shales. A brand-new characteristic parameter, T1/T2 variation during a solvent extraction experiment, is proposed for the characterization of shale petrophysical properties. The theoretical ranges of T1/T2 variation for different hydrogen components were determined from the type and content changes of hydrogen during extraction based on surface relaxation model. Joint experiments of multi-step solvent extraction and NMR T1-T2 were designed to validate the theoretical results. Both theoretical and experimental results show that the heterogeneity of shale is responsible for the different hydrogen components with a similar T1/T2 value. The results of joint experiment (1) show that the T1/T2 variation ranges for different hydrogen components are different, and (2) indicate that T1/T2 variations can be used to quantitatively evaluate the hydrogen type and saturation. The experimentally determined ranges and patterns of T1/T2 variation are consistent with the theoretical results. The quantitative relationship between T1/T2 variation and saturation, mobility, or wettability was further determined based on the theoretical variation of correlation time. Finally, a new interpretation scheme was established for the quantitative evaluation of wettability and fluid properties based on T1/T2 variations.

Application of AFM on Identifying Mechanical Properties of Individual Minerals and Surface Properties of Crack with High Resolution in Shale

Improving the resolution and accuracy of the mechanical properties of organic-rich shale is very important. The results can reveal the mechanical properties of shale from micro scale and serve as a guide for the design of hydraulic fracture optimization parameters. This study introduced an advanced technique to obtain the mechanical properties of shale with high resolution (58.6 nm/pixel) by combining SEM, EDS, and Atomic Force Microscopy (AFM). To locate the target area in SEM and AFM accurately, a positioning technique that uses special distributions of pyrite was established. AFM PeakForce QNM mode was selected due to its advantages at capturing topography and mechanical properties in material. Results illustrated the ability of AFM to obtain the mechanical properties (modulus) of individual mineral components in shale, the detailed topography of crack, and mechanical properties of minerals in a specific area. In particular, the mechanical properties of minerals around crack explained the layered distribution of minerals around the fractures, and the cracks developed in the clay mineral layer was detected. This article demonstrates the great potential application of AFM in shale.

Average molecular structure model of shale kerogen: Experimental characterization, structural reconstruction, and pyrolysis analysis

Shale can be both a source rock and a reservoir rock, which is a typical self-generating and self-storing type of oil accumulation. Its main organic component is kerogen. Using molecular dynamics (MD), a realistic kerogen molecular structure model is an alternative to experimental and analytical-only approaches for studying shale organic matter's microscopic properties. Therefore, it is useful to establish an average molecular structure model for shale kerogen. Moreover, the pyrolysis mechanism of shale kerogen is of great significance for developing and utilizing shale mineral resources. In this study, geochemical and spectroscopic measurements such as the elemental analysis, 13C nuclear magnetic resonance spectroscopy (13C NMR), Fourier transform infrared spectroscopy (FTIR), and X-ray photoelectron spectroscopy (XPS) were used to obtain information about the carbon skeleton, aliphatic structures, and aromatic structures of the kerogen. Following information analysis and molecular fragment splicing, a 2D molecular structure model of kerogen from the Nanpu shale, with the chemical formula C199H240O20N6S2 and molecular weight of 3096 Daltons was constructed. After that, the accuracy of the 2D structure was verified by comparing the 13C NMR spectra simulated by the 2D structure to the experimental spectra. Using MD simulation, based on the kerogen density, 10 2D structures are then combined to create a realistic 3D molecular structure model of kerogen. Finally, pyrolysis analysis was performed based on the established 3D molecular structure model of kerogen to determine the effect of temperature on pyrolysis. Using the advantages of various technologies, this study not only provides a systematic method for establishing a realistic 3D molecular structure model of kerogen but also contributes to in-depth research on the reaction mechanism of kerogen pyrolysis, providing a reliable foundation for future research on the properties of shale at the molecular scale.

Origins of Siliceous Minerals and Their Influences on Organic Matter Enrichment and Reservoir Physical Properties of Deep Marine Shale in the Sichuan Basin, South China

Origins of Siliceous Minerals and Their Influences on Organic Matter Enrichment and Reservoir Physical Properties of Deep Marine Shale in the Sichuan Basin, South China

Performance evaluation of different cationic surfactants as anti-swelling agents for shale formations

In this study, three different novel cationic surfactants decyl-trimethyl-ammonium bromide (S1), Octyl-trimethyl-ammonium bromide (S2), hexyl-trimethyl-ammonium bromide (S3) were used to formulate water-based drilling formulations to comprehend the interactions between drilling fluids components and with wellbore formations. The modified drilling formulations were prepared by incorporating novel surfactants in the base mud along with other additives such as bentonite, PAL-C, xanthan gum, and barite. The effect of the surfactant's chemical structure was assessed by rheology and filtration experiments, and colloidal dispersion stability was determined by particle size distribution analysis and sedimentation tests. The shale swelling inhibition characteristics of surfactant-based formulations were accessed by hot rolling dispersion tests, linear swelling rates, and capillary suction time tests. The performance of surfactant-based formulations for shale swelling inhibition was compared with KCl-based and conventionally used base mud formulations. The surface wettability of shale in the presence of different formulations was assessed by a high-resolution optical tensiometer. Shale inhibition properties of surfactant-based formulations depict that shale dispersion recovery increased to 98% for BS1 formulation compared to all other used formulations. Linear swelling of shale pellet show that the swelling rate of BS1 formulation was only 13% compared to all other formulations. The contact angle experiments showed that the BS1 formulation increased the contact angle of a water droplet and reduced the wettability of drilling fluids. The experimental results showed that S1 surfactant has enhanced shale inhibition characteristics compared to other surfactants and conventionally used shale inhibitors.

Mechanisms of the imbibition behavior in shales: A critical review

Despite the success of hydraulic fracturing in yielding large production increases from shale gas reservoirs, uncertainties associated with basic transport processes require understanding in order to improve the efficiency and minimize environmental impacts. The hydraulic fracturing process brings in large volumes of water into shale reservoir formations, most of which remains unrecoverable and interferes with shale gas production. The imbibition behavior in shales is commonly observed during the hydraulic fracturing process, and the mechanism greatly influences the hydrocarbon recovery in shale gas reservoirs. In this review, the imbibition models in shales are briefly summarized using the Lucas–Washburn model, piston repulsion model, capillary bundle model, and scalar model. Then the experimental study and numerical simulation of shale imbibition are discussed. Moreover, the influencing factors of the imbibition behavior in shales are analyzed, such as shale and fluid properties. Finally, the main conclusions and the future research direction prospects of the imbibition behavior in shale gas reservoirs are summarized. An accurate description of the imbibition behavior in shale is crucial for optimizing the hydraulic fracturing design and enhancing shale gas production in the development of shale gas reservoirs. It is proposed that the research on the individual influencing factors of shale percolation and the geological mechanism under coupling should be strengthened and that the research on the experimental aspects of shale powder percolation should be emphasized.

Micro-mechanical properties of shale due to water/supercritical carbon dioxide-rock interaction

To investigate the impacts of water/supercritical CO2-rock interaction on the micro-mechanical properties of shale, a series of high-temperature and high-pressure immersion experiments were performed on the calcareous laminated shale samples mined from the lower submember of the third member of Paleogene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin. After that, grid nanoindentation tests were conducted to analyze the influence of immersion time, pressure, and temperature on micro-mechanical parameters. Experimental results show that the damage of shale caused by the water/supercritical CO2-rock interaction was mainly featured by the generation of induced fractures in the clay-rich laminae. In the case of soaking with supercritical CO2, the aperture of induced fracture was smaller. Due to the existence of induced fractures, the statistical averages of elastic modulus and hardness both decreased. Meanwhile, compaction and stress-induced tensile fractures could be observed around the laminae. Generally, the longer the soaking time, the higher the soaking pressure and temperature, the more significant the degradation of micro-mechanical parameters is. Compared with water-rock interaction, the supercritical CO2-rock interaction caused a lower degree of mechanical damage on the shale surface. Thus, supercritical CO2 can be used as a fracturing fluid to prevent the surface softening of induced fractures in shale reservoirs.

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.

Concurrent influence of geological parameters on the integrated nano-pore structure and discretized pore families of the petroliferous Cambay shale assessed through multivariate dependence measure

Heterogeneous nanopore structure and distribution regulate the gas trapping, desorption kinetics, and diffusion in shale matrices. In shale, pores range from continuous micro- and mesopore size distributions, varying with organic (total organic matter-TOC) and inorganic constituents (clay content, Fe-bearing minerals, quartz, etc.). Previous research only showed a linear relationship of pore parameters with these intrinsic properties of shale, which limits our understanding of the concurrent influence of multiple intrinsic rock properties. As a result, in this work, we established multivariate dependency of nanopore structure, distribution, and complexity (from low-pressure N2 and CO2 sorption and small-angle scattering; SAXS/MSANS) in the previously little-studied Cambay shales and provided a better tool (partial least square regression) for analyzing the simultaneous effect of intrinsic shale properties on multiply connected pore-parameters. Furthermore, we discretized continuous pore-size distribution into individual pore families using deconvolution to understand the pore space better. Additionally, predicted shale formation environment in terms of deposition probability (P+) and dissolution probability (P−) using a dynamic model of the fractal interface by precipitation and dissolution. Our findings indicate that the Cambay shales have a high potential for future hydrocarbon exploration (S2: 2.42–12.04 mg HC/g rock), “very good” (2-4 wt.%) to “excellent” (>4 wt.%) TOC content, and thermally mature type II–III admixed and type III kerogen. Deconvolution of the micro- and mesopore size distributions reveals that pore width (w) ranges ∼15.30–35 nm occupies greater than 50% of the total pore volume, and its pore volume increases with the presence of quartz, Fe-bearing minerals, and clay content. However, pores with w∼ 3.60–15.30 nm increase exclusively with TOC. In the micro- and early mesopore region, pore volume decreases with TOC from w∼ 0.30–0.75 nm and increases with TOC from w∼ 0.75–3.60 nm. Furthermore, TOC in shale increases the specific surface area and pore volume (micro-, meso-, and total pores), enhancing both sorption and free gas storage capacities. Cambay shales were likely deposited in three distinct environments, with precipitation probability (P+) values of 1, 0.7–0.8, and 0.5, as revealed by a fractal dimension (Ds) analysis of multiple samples.

Determination of Shale Gas-Bearing Properties Based on Carbon Isotope Fractionation Model: A Case Study from Longmaxi Formation Shales in Jiaoshiba Area, Sichuan Basin, China

Determination of Shale Gas-Bearing Properties Based on Carbon Isotope Fractionation Model: A Case Study from Longmaxi Formation Shales in Jiaoshiba Area, Sichuan Basin, China

Experimental investigation on the anisotropy of mode-I fracture and tensile failure of layered shale

Mode-I fracture toughness (KIC) and tensile strength (σt) are significant parameters in hydraulic fracturing. Owing to the unique mineral composition and sedimentary environment of shale, the mechanical properties of shale exhibit anisotropy. In this study, the notched semi-circular bend (NSCB) and Brazilian disc (BD) tests were combined with acoustic emission (AE) and digital image correlation (DIC) technology to investigate the anisotropic fracture and tensile behaviors of layered shale. The critical plane approach (CPA) criterion is extended and validated, and the universality of the extended CPA criterion is confirmed for both KIC and σt prediction. In addition, the variation of KIC and σt versus loading angle, the relationship between KIC and σt, the typical failure modes of both NSCB and BD specimens, and the fracture initiation angle of layered shales are discussed comprehensively. The following conclusions were drawn: (1) KIC and σt increased with increasing in the loading angle (β), which indicated significant anisotropy of layered shale, and the AE responses for different loading angles also differed significantly. (2) The variation of anisotropic KIC and σt of different shales could be predicted by adjusting the spatial distribution parameter (Ω0), so that the extended CPA criterion could predict KIC and σt of different shales accurately, which confirmed the universality of the extended CPA criterion for both KIC and σt prediction. (3) There exists an approximately linear or power relationship between KIC and σt, and the power relationship can match both experimental and theoretical results much better. (4) The data from DIC and failure modes confirmed that when β was low, the failure modes were primarily affected by the bedding plane. In contrast, when β was great, the failure modes were primarily affected by the matrix. The NSCB specimens exhibited tensile failure, whereas the BD specimens exhibited more complex failure modes, which were a combination of tensile and shear failure. The results of this study can be used for guiding the design and construction of hydraulic fracturing and rock engineering.

Experimental and constitutive modeling of the anisotropic mechanical properties of shale subjected to thermal treatment

The physical and mechanical properties of shale exhibit significant anisotropy, impacting the design and construction of high geothermal tunnels and deep resource mining. Laboratory studies on the physical and anisotropic mechanical properties of shale after various thermal treatments showed that rising temperatures caused an exponential decline in shale’s bulk and density, and the uneven expansion of the mineral particles within the rock caused a decrease in its uniaxial compression strength (UCS) and elastic modulus while increasing their anisotropy. The UCS is U-shaped with a change in bedding dip angle, whereas the elastic modulus is U-shaped or shoulder-shaped. Under the assumption that the rock microelement obeyed the Weibull distribution, the microstructure tensor improved Hoek–Brown strength criterion was introduced as the damage basis. Then a thermal–mechanical coupling damage constitutive model considering bedding dip angle and temperature was established. The model was found to be valid via the test results, especially in capturing the compaction and yield softening stages of shale. These findings have reference value for both underground structural engineering and deep resource mining.

Reservoir Characteristics and Influencing Factors of Organic-Rich Siliceous Shale of the Upper Permian Dalong Formation in Western Hubei

To elucidate the reservoir characteristics of organic-rich siliceous shale of the Upper Permian Dalong Formation in western Hubei, this study focused on the drilling cores of Well ED-2. Various techniques, including a mineral composition analysis, an organic carbon content analysis, a vitrinite reflectance measurement, a total porosity determination, field emission scanning electron microscopy (FE-SEM), and low-pressure CO2 and N2 physical adsorption tests, were employed to analyze the mineralogy, organic geochemistry, total porosity, and pore structure characteristics. Additionally, the factors influencing the reservoir performance of the Dalong Formation shale were investigated. The results indicated that the Dalong Formation’s shale was characterized as an organic-rich siliceous shale. Organic matter was mainly of sapropelic type, with a relatively high thermal evolution degree and Ro ranging from 2.59% to 2.76%. The total porosity of the Dalong Formation’s siliceous shale was low, indicating poor reservoir properties. Organic matter pores were highly developed, mainly the ones formed after the hydrocarbon generation of solid asphalt. Micropores and mesopores were the dominant pore types in the shale, with macropores being significantly less abundant. The study further revealed that the pore volume and specific surface area exhibited a significantly positive correlation with total organic carbon (TOC) content and clay minerals, while demonstrating a weak negative correlation with quartz content. The comprehensive analysis revealed that there were two factors contributing to the poor physical properties of organic-rich siliceous shale in the Dalong Formation. Firstly, in siliceous shale with a high quartz content, the siliceous component was partly derived from the siliceous cementation of hydrothermal fluids. This process led to the formation of secondary quartz that filled intergranular pores, resulting in a decrease in macropore volume, total porosity, and a weak negative correlation with quartz content. Secondly, in siliceous shale with a relatively high clay mineral content, the organic matter was subjected to stronger compaction due to the relatively low content of brittle minerals. This compaction caused the destruction of most macropores, leaving behind primarily micropores and mesopores. Consequently, the average pore size decreased, leading to poor physical properties.

Data-driven models to predict shale wettability for CO2 sequestration applications

The significance of CO2 wetting behavior in shale formations has been emphasized in various CO2 sequestration applications. Traditional laboratory experimental techniques used to assess shale wettability are complex and time-consuming. To overcome these limitations, the study proposes the use of machine learning (ML); artificial neural networks (ANN), support vector machines (SVM), and adaptive neuro-fuzzy inference systems (ANFIS) tools to estimate the contact angle, a key indicator of shale wettability, providing a more efficient alternative to conventional laboratory methods. A dataset comprising various shale samples under different conditions was collected to predict shale-water-CO2 wettability by considering shale properties, operating pressure and temperature, and brine salinity. Pearson’s correlation coefficient (R) was utilized to assess the linearity between the contact angle (CA) value and other input parameters. Initial data analysis showed that the elements affecting the shale wettability are primarily reliant on the pressure and temperature at which it operates, the total organic content (TOC), and the mineral composition of the rock. Between the different ML models, the artificial neural network (ANN) model performed the best, achieving a training R2 of 0.99, testing R2 of 0.98 and a validation R2 of 0.96, with an RMSE below 5. The adaptive neuro-fuzzy inference system (ANFIS) model also accurately predicted the contact angle, obtaining a training R2 of 0.99, testing R2 of 0.97 and a validation R2 of 0.95. Conversely, the support vector machine (SVM) model displayed signs of overfitting, as it achieved R2 values of 0.99 in the training dataset, which decreased to 0.94 in the testing dataset, and 0.88 in the validation dataset. To avoid rerunning the ML models, an empirical correlation was developed based on the optimized weights and biases obtained from the ANN model to predict contact angle values using input parameters and the validation data set revealed R2 of 0.96. The parametric study showed that, among the factors influencing shale wettability at a constant TOC, pressure had the most significant impact, and the dependency of the contact angle on pressure increased when TOC values were high.

Research on the inherent mechanism of rock mass deformation of oil shale in-situ mining under the condition of thermal-fluid-solid coupling

With the gradual maturity of in-situ mining technology of oil shale, environmental geological problems such as ground subsidence after mining become increasingly important. The existing researches focus more on the improvement of mining technology, but less on the deformation of oil shale after mining. In this study, various experiments are used to test the pore characteristics and mechanical properties of oil shale with temperature. It is found that parallel bedding macro fractures are formed during oil shale pyrolysis, and the mechanical properties change differently in parallel and vertical bedding directions. The anisotropy of mechanical properties of oil shale is related to the anisotropy of pore structure for the first time to explains the mechanism of deformation. Moreover, the constitutive model of in-situ mining deformation of oil shale is established through statistical damage mechanics combined with pore structure. The deformation of in-situ mining of oil shale under thermal-fluid-solid coupling condition is studied by combining the constitutive model with multi-field coupling numerical simulation. The results show that the compression deformation of oil shale is about 6.5 cm per meter at 200 m underground, and the impact of in-situ mining on geological environment is less than that of traditional mining methods.

Experimental study on the static and dynamic elastic stiffness of rock samples from a shale oil reservoir

Shale reservoirs play essential roles in numerous geoengineering applications, including storing CO2 and radioactive waste and producing hydrocarbons. To fulfill these applications, the mechanical properties of shale are of great interest so that people can locate shales with preferred sealing or frackable characteristics. One can estimate the static stiffness related to the rock deformation from the dynamic stiffness derived from the wave velocity through some empirical correlations. However, a gap exists between dynamic and static stiffness in sedimentary rocks. Anisotropy further complicates the prediction of the static stiffness from the dynamic stiffness of shale. This paper investigates the link and contrast between the dynamic and static stiffness and the effects of anisotropy by performing triaxial tests on two shale samples cored in the vertical and horizontal directions from a shale oil reservoir in China. We analyze the effects of stress (strain) rate, stress (strain) amplitude, and the base level of deviatoric stress. The secant Young’s modulus is found to decrease with the increasing stress rate or stress amplitude. By introducing the nonlinear elastic theory, Young’s modulus can be expressed as a linear function of axial strain, where the slope is related to the stress sensitivity of the static stiffness, and the intercept is associated with the elastic property at the infinitesimal strain. The slopes and intercepts of linear functions are negatively correlated. Furthermore, six linear fittings from the two samples in the three tests are found to link with the strain amplitude, the base stress level, and anisotropy. This study provides insights into the prediction of static stiffness from dynamic one. With proper models of dynamic-static transition, seismic or wireline logging measurements can assist in solving engineering issues. People can better ensure the quality of the geomechanical model and reduce the cost of various engineering applications.