Minerals In Shale Research Articles

The impact of pore heterogeneity on pore connectivity and the controlling factors utilizing spontaneous imbibition combined with multifractal dimensions: Insight from the Longmaxi Formation in Northern Guizhou

The heterogeneity of shale pores, a crucial factor in the occurrence and migration of shale gas, exerts a significant impact on the pore connectivity. Pores exhibiting a range of structural attributes to the complexity of pore connectivity. A comprehensive study into the impact of pore heterogeneity on pore connectivity in shale is lacking. This study aims to explore the impact of pore heterogeneity on pore connectivity in shale and the primary controlling factors of pore connectivity. Shale pore connectivity, pore structures, mineral composition, and geochemical parameters were assessed using various tests, including spontaneous imbibition, adsorption, mercury intrusion capillary pressure (MICP), focus ion beam-scanning electron microscopy (FIB-SEM), sulfur and carbon analysis, vitrinite reflectivity, and X-ray diffraction (XRD). Pore heterogeneity was quantitatively analyzed using the multifractal dimensions method. Results show that the increased heterogeneity of pore structure and surface roughness facilitating the potential for increased connectivity. The presence of well-developed micro-mesopores within the organic matter, alongside numerous disconnected and independent pores, contributes to an increase in pore heterogeneity. Micro-mesopore structures have a more pronounced impact on pore heterogeneity than macropores. The heterogeneity of the pores is predominantly influenced by variations in the PV and SSA of micro-mesopores. Furthermore, the heightened heterogeneity of pore structure (D1) and surface roughness (D2) leads to a more complex pore structure with increased roughness, promoting the potential for enhanced connectivity through additional throats and facilitating the formation of secondary microfractures. Shale cores characterized by high total organic carbon (TOC) content, porosity, and clay mineral content are conducive to improved pore connectivity. Conversely, the increase of thermal evolution maturity of shale in the over-mature stage is not conducive to the increase of pore connectivity. Thermal evolution maturity, TOC content, and clay mineral are key factors that control pore heterogeneity, further affecting the connectivity of shale pores. High pore connectivity is conducive to spontaneous imbibition capacity and the formation of hydraulic microfractures, promoting the migration of shale gas.

Comprehensive extraction of V, Ni and Mo from black shale via selective leaching oxidation process

Black shale is one of the most representative sources of vanadium, nickel and molybdenum in China. Due to the poor endowment of minerals in black shale, V, Ni, Mo and other metals complex co-associated endowment state, extraction is difficult and long-term unused, resulting in a significant waste of resources. In this paper, it is shown that V, Ni and Mo can be obtained from black shale by a stepwise oxidation leaching process. In a first leaching process, V and Ni are effectively leached simultaneously. Mo is left in the residue. The leaching efficiency of V, Ni and Mo was 86.81%, 89.19% and 5.80% respectively under the leaching conditions of 35wt.% H2SO4, 4wt.% CaF2, 1.2:1 liquid to solid ratio (L/kg), 95℃ and 8h. The residue was then leached twice. The leaching efficiency of molybdenum was 91.10% under the leaching conditions of 25wt.% H2SO4, 8wt.% NaClO3, 1.5:1 liquid to solid ratio (L/kg), 45℃ and 7h. V2O5 products have been successfully prepared, the purity of V2O5 reaches 98.34%. A stepwise oxidation leaching method has been proposed to separate the vanadium, nickel and molybdenum in the leaching process. Vanadium, nickel and molybdenum can be effectively extracted from the black shale by the stepwise oxidation leaching process to maximize the utilization of the resources.

Shale Reservoir Rock Physics Modeling and “Sweet Spot” Prediction Based on Digital Core

Abstract With the increasing advancement in shale exploration and development, the complex pore structure and organic-rich characteristics of shale have gradually become the focus of rock physics models. This study combined digital core technology to obtain detailed information on the shale mineral composition, content, pore and crack contents, and composition. The isotropic self-compatible approximation (SCA) model was used to couple the shale minerals and hard pores to construct a brittle mineral framework. The VRH model was used to mix kerogen and clay, and the SCA-DEM (differential equivalent medium) model was used to add organic pores to construct a clay-organic matter mineral framework. The anisotropic SCA model treated the clay-organic matter mineral framework as an inclusion added to the brittle mineral framework to construct the shale mineral framework. The Eshelby–Cheng model was used to add fracture to the mineral framework and establish a physical shale model. This model was used to optimise the selection of sensitive elastic parameters for physical properties such as brittle mineral and kerogen content, fracture density, and porosity, and the optimisation results were combined to construct an explanatory quantity template. In addition, according to actual data from a study area in southwestern China, we combined to the interpretation chart established by the model to perform isotropic inversion. Then, we analyzed and interpreted the brittleness index (BI) and total organic carbon (TOC) content of the reservoir and predicted the sweet spot area of the shale reservoir.

Paleoenvironmental Transition during the Rhuddanian–Aeronian and Its Implications for Lithofacies Evolution and Shale Gas Exploration: Insights from the Changning Area, Southern Sichuan Basin, South-West China

During the Rhuddanian–Aeronian interglacial period, global geological events such as glacial melting, synsedimentary volcanic activity, biological resurgence, and large-scale marine transgressions caused frequent fluctuations in paleoproductivity, climate changes, and sea level variations. These paleoenvironmental transitions directly influenced the development characteristics of shale lithofacies. This study investigates the Longmaxi Formation shale in the Changning area in the Southern Sichuan basin, focusing on 28 core samples from Well N1. Using scanning electron microscopy, QEMSCAN, TOC, XRD, and major and trace element analyses, we reconstructed the paleoenvironmental transitions of this period and explored their control over shale lithofacies types and mineral compositions. Four shale lithofacies were identified: carbonate rich lithofacies (CRF), biogenic quartz-rich lithofacies (BQRF), detrital clay-rich lithofacies (CRDF), and detrital quartz-rich lithofacies (DQRF). During the Rhuddanian period, rising global temperatures caused glacial melting and rapid marine transgressions. The low oxygen levels in bottom waters, combined with upwelling and abundant volcanic material, led to high paleoproductivity. This period primarily developed BQRF and CRF. Rich nutrients and abundant siliceous organisms, along with anoxic to anaerobic conditions, provided the material basis and preservation conditions for high biogenic quartz and organic matter content. High paleoproductivity and anoxic conditions also facilitated the precipitation of synsedimentary calcite and supplied Mg2+ and SO42− for the formation of iron-poor dolomite via sulfate reduction. From the Late Rhuddanian to the Mid-Aeronian, the Guangxi orogeny caused sea levels to fall, increasing water oxidation and reducing upwelling and volcanic activity, which lowered paleoproductivity. Rapid sedimentation rates, stepwise global temperature increases, and the intermittent intensification of weathering affected terrigenous clastic input, resulting in the alternating deposition of CRF, CRDF, and DQRF. Two favorable shale gas reservoirs were identified from the Rhuddanian–Aeronian period: Type I (BQRF) in the L1–L3 Layers, characterized by high TOC and brittleness, and Type II (DQRF) in the L4 Layer, with significant detrital quartz content. The Type I-favorable reservoir supports ongoing gas production, and the Type II-favorable reservoir offers potential as a future exploration target.

Study on the evaluation of shale reservoir brittleness based on mineral disorder

Brittleness serves as a critical indicator for assessing whether reservoirs can form complex fracture networks. While methods based on brittle mineral content or rock mechanical parameters are widely used, their lack of integration between mineralogy and mechanics introduces limitations. A single evaluation parameter cannot accurately assess shale brittleness. There is a need for a universally applicable method that comprehensively considers mineral composition, mechanical properties, and brittleness variations in shale evaluation. This study uses Longmaxi shale in the Sichuan Basin as an example, establishing a mineral disorder index based on shale mineral composition and mechanical characteristics, incorporating the influence of confining pressure to establish a shale brittleness index. Results indicate varying weights of brittleness contributions from different minerals, ranked in descending order: pyrite, quartz, calcite, dolomite, feldspar, and clay. Greater complexity in mineral combinations correlates with lower shale brittleness indices. Typically, single mineral disorder indices show a positive correlation with internal mineral disorder indices. Confining pressure exhibits an inversely proportional relationship with shale brittleness indices, with brittleness at 30, 50, and 70 MPa confining pressures being 0.737, 0.586, and 0.451 times those without confining pressure, respectively. This method guides current brittleness research and reservoir production enhancement.

Shale mineral interactions and interfacial mechanical properties modeled by molecular dynamics

Shale mineral interactions and interfacial mechanical properties modeled by molecular dynamics

Constraining Geogenic Sources of Boron Impacting Groundwater and Wells in the Newark Basin, USA

The Newark Basin comprises Late Triassic and Early Jurassic fluvio-lacustrine rocks (Stockton, Lockatong, Passaic, Feltville, Towaco, and Boonton Formations) and Early Jurassic diabase intrusions and basalt lava flows. Boron concentrations in private well water samples range up to 18,000 μg/L, exceeding the U.S. Environmental Protection Agency Health Advisory of 2000 μg/L for children and 5000 μg/L for adults. Boron was analyzed in minerals, rocks, and water samples using FUS-ICPMS, LA-ICP-MS, and MC ICP-MS, respectively. Boron concentrations reach up to 121 ppm in sandstone of the Passaic Formation, 42 ppm in black shale of the Lockatong Formation, 31.2 ppm in sandstone of the Stockton Formation, and 36 ppm in diabase. The δ11B isotopic values of groundwater range from 16.7 to 32.7‰, which fall within those of the diabase intrusion (25 to 31‰). Geostatistical analysis using Principal Component Analysis (PCA) reveals that boron is associated with clay minerals in black shales and with Na-bearing minerals (possibly feldspar and evaporite minerals) in sandstones. The PCA also shows that boron is not associated with any major phases in diabase intrusion, and is likely remobilized from the surrounding rocks by the intrusion-related late hydrothermal fluids and subsequently incorporated into diabase. Calcite veins found within the Triassic rock formations exhibit relatively elevated concentrations ranging from 6.3 to 97.3 ppm and may contain micro-inclusions rich in boron. Based on the available data, it is suggested that the primary sources of boron contaminating groundwater in the area are clay minerals in black shales, Na-bearing minerals in sandstone, diabase intrusion-related hydrothermal fluids, and a contribution from calcite veins.

The Roles of Micro Pores and Minerals in Shale during Hydraulic Fracturing

The Roles of Micro Pores and Minerals in Shale during Hydraulic Fracturing

Machine learning-based grayscale analyses for lithofacies identification of the Shahejie Formation, Bohai Bay Basin, China

It is of great significance to accurately and rapidly identify shale lithofacies in relation to the evaluation and prediction of sweet spots for shale oil and gas reservoirs. To address the problem of low resolution in logging curves, this study establishes a grayscale-phase model based on high-resolution grayscale curves using clustering analysis algorithms for shale lithofacies identification, working with the Shahejie Formation, Bohai Bay Basin, China. The grayscale phase is defined as the sum of absolute grayscale and relative amplitude as well as their features. The absolute grayscale is the absolute magnitude of the gray values and is utilized for evaluating the material composition (mineral composition + total organic carbon) of shale, while the relative amplitude is the difference between adjacent gray values and is used to identify the shale structure type. The research results show that the grayscale phase model can identify shale lithofacies well, and the accuracy and applicability of this model were verified by the fitting relationship between absolute grayscale and shale mineral composition, as well as corresponding relationships between relative amplitudes and laminae development in shales. Four lithofacies are identified in the target layer of the study area: massive mixed shale, laminated mixed shale, massive calcareous shale and laminated calcareous shale. This method can not only effectively characterize the material composition of shale, but also numerically characterize the development degree of shale laminae, and solve the problem that difficult to identify millimeter-scale laminae based on logging curves, which can provide technical support for shale lithofacies identification, sweet spot evaluation and prediction of complex continental lacustrine basins.

Research on quantitative analysis method of shale oil reservoir sensitivity based on mineral analysis

Mineral compositions of shale reservoirs are complex and highly influenced by external fluids. At present, there are limited studies on the effect of mineral expansion rate on external fluids, and there is a lack of systematic research on the sensitivity of shale reservoir porosity to external fluids. In this paper, firstly, X-Ray Diffractometer (XRD) experiments were carried out to study the mineral composition of shale reservoirs, revealing the mechanism of shale minerals interacting with acidic/alkaline fluids. Secondly, the sensitivity evaluation experiments of single mineral external fluid immersion were conducted on the main minerals in shale. Finally, a prediction method for the sensitivity of shale reservoir porosity to external fluids (acidic/alkaline fluids, oil slicks) was established. The results show that: (a) Volume expansion of quartz after 48 h of immersion in alkaline fluids at pH = 9 and pH = 11 and the expansion rate is maximum at pH = 9 i.e. 0.16. (b) Volume expansion of chlorite after 48 h immersion in alkaline fluid and maximum expansion at pH = 13 i.e. 0.55. (c) The improvement of total porosity of shale by acid solution is weak. (e) Alkaline solution has a weak damage to the total porosity of shale, and the degree of damage increases and then decreases with the increase of the strength of alkaline solution.

Cross-scale mechanical softening of Marcellus shale induced by CO2-water–rock interactions using nanoindentation and accurate grain-based modeling

Mechanical softening behaviors of shale in CO2-water–rock interaction are critical for shale gas exploitation and CO2 sequestration. This work investigated the cross-scale mechanical softening of shale triggered by CO2-water–rock interaction. Initially, the mechanical softening of shale following 30 d of exposure to CO2 and water was assessed at the rock-forming mineral scale using nanoindentation. The mechanical alterations of rock-forming minerals, including quartz, muscovite, chlorite, and kaolinite, were analyzed and compared. Subsequently, an accurate grain-based modeling (AGBM) was proposed to upscale the nanoindentation results. Numerical models were generated based on the real microstructure of shale derived from TESCAN integrated minerals analyzer (TIMA) digital images. Mechanical parameters of shale minerals determined by nanoindentation served as input material properties for AGBMs. Finally, numerical simulations of uniaxial compression tests were conducted to investigate the impact of mineral softening on the macroscopic Young’s modulus and uniaxial compressive strength (UCS) of shale. The results present direct evidence of shale mineral softening during CO2-water–rock interaction and explore its influence on the upscale mechanical properties of shale. This paper offers a microscopic perspective for comprehending CO2-water-shale interactions and contributes to the development of a cross-scale mechanical model for shale.

Pore Fractal Characteristics between Marine and Marine–Continental Transitional Black Shales: A Case Study of Niutitang Formation and Longtan Formation

Marine shales from the Niutitang Formation and marine–continental transitional shales from the Longtan Formation are two sets of extremely important hydrocarbon source rocks in South China. In order to quantitatively compare the pore complexity characteristics between marine and marine–continental transitional shales, the shale and kerogen of the Niutitang Formation and the Longtan Formation are taken as our research subjects. Based on organic petrology, geochemistry, and low-temperature gas adsorption analyses, the fractal dimension of their pores is calculated by the Frenkel–Halsey–Hill (FHH) and Sierpinski models, and the influences of total organic carbon (TOC), vitrinite reflectance (Ro), and mineral composition on the pore fractals of the shale and kerogen are discussed. Our results show the following: (1) Marine shale predominantly has wedge-shaped and slit pores, while marine–continental transitional shale has inkpot-shaped and slit pores. (2) Cylindrical pores are common in organic matter of both shale types, with marine shale having a greater gas storage space (CRV) from organic matter pores, while marine–continental transitional shale relies more on inorganic pores, especially interlayer clay mineral pores, for gas storage due to their large specific surface area and high adsorption capacity (CRA). (3) The fractal characteristics of marine and marine–continental transitional shale pores are influenced differently. In marine shale, TOC positively correlates with fractal dimensions, while in marine–continental shale, Ro and clay minerals have a stronger influence. Ro is the primary factor affecting organic matter pore complexity. (4) Our two pore fractal models show that the complexity of the shale in the Longtan Formation surpasses that of the shale in the Niutitang Formation, and type I kerogen has more complex organic matter pores than type III, aiding in evaluating pore connectivity and flow effectiveness in shale reservoirs.

Comparison of the Sample Preparation Strategies and Impacts on the Tensile Strength of Gas Shale with Variable Moisture Conditions

Moisture significantly affects the mechanical behavior of gas shale and further determines the hydraulic fracturing performance, as it is more attractive. Nevertheless, batch experiments have usually involved variable methodologies regarding the preparation of moisture-contained shale specimens in the sequence (and/or frequency) of drying and soaking treatments. Accordingly, this work investigates how the preparation methodology influences the test results of moisture-contained shale samples. This study compares three commonly used shale sample preparation strategies for acquiring different moisture contents, that is, “dry-wet”, “dry-wet-dry”, and “wet-dry-wet” strategies, followed by a Brazilian splitting test for the mechanical parameters. The results show that under the same saturation conditions, the longer the soaking time during sample preparation, the higher the degradation degree of shale tensile strength. Meanwhile, prolonged soaking can lead to a more discrete distribution of strength values, and the failure mode may deviate from the Brazilian splitting theory model. Under the combined influence of moisture content and soaking time, the tensile strength of shale decreases approximately linearly with increasing saturation, while the degradation degree increases nonlinearly with increasing saturation, and the degradation rate changes from slow to fast. According to the observation of the microstructure of hydrated shale, prolonged soaking can lead to an increase in the expansion of clay minerals in shale by hydration, resulting in looser and more fragmented internal structure, and further degradation in shale strength. In order to weaken the interference of hydration when studying the effect of moisture content on the tensile strength of shale, the soaking time should be minimized as much as possible during the preparation process.

In-situ laboratory study on influencing factors of pre-SC-CO2 hybrid fracturing effect in shale oil reservoirs

Supercritical CO2 (SC-CO2) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO2 hybrid fracturing method has been proposed, which combines the advantages of SC-CO2 fracturing and hydraulic fracturing. However, the specific impacts of different pre–SC-CO2 injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO2 injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO2 injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO2 leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO2 injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO2 is positively correlated with the injection displacement and volume. Additionally, pre-injection of SC-CO2 enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO2 injection parameters. Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO2 hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO2 injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of preSC-CO2 hybrid fracturing in shale oil reservoirs.

Research on the Shale Reservoir Sensitivity by Using the Mineral Analysis Method.

Shale reservoirs have diverse mineral types, and analyzing the sensitivity of the mineral composition to shale pores is of great scientific and engineering significance. In this paper, first, X-ray diffraction (XRD) experiments on shale mineral compositions are carried out, and the characteristics of pore structure changes after shale mineral compositions interacted with external fluids (slick water and backflow fluid) are elucidated. Then, the effects of quartz, kaolinite, and pyrite on the pore structure and permeability of shale on the susceptibility to slick water are studied. The results show that (a) quartz and clay minerals are the dominant constituents of each core, with some cores containing minor amounts of plagioclase feldspar and rhodochrosite. (b) The composition of the shale changed significantly following the action of external fluids. The average quartz content of pure shale decreased from 31.62% to 29.1%. The average content of quartz in siliceous shale decreased from 36.53% to 33.5%. The average content of quartz in carbonaceous shale decreased from 9.15% to 8.05%. (c) Factors affecting the sensitivity of shale pore structure and permeability to slick water are mainly quartz, kaolinite, and pyrite. The contents of quartz, kaolinite, and pyrite decreased by an average of 5.1%, 4.6%, and 0.9%, respectively, after slick water action.

Influence of Shale Mineral Composition and Proppant Filling Patterns on Stress Sensitivity in Shale Reservoirs

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m2 is 3.61 times that of cores with a proppant concentration of 0.3 kg/m2. Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages.

Formation damage mechanism and control strategy of the compound function of drilling fluid and fracturing fluid in shale reservoirs

For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid, the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid. With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface, fracture closure and rock powder blocking, the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid. The formation damage mechanism during drilling and completion process in shale reservoir is revealed, and the protection measures are raised. The drilling fluid can deeply invade into the shale formation through natural and induced fractures, erode shale minerals and weaken the mechanical properties of shale during the drilling process. In the process of hydraulic fracturing, the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale, results in fracture closure and rock powder shedding, and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures. The damage can yield significant conductivity decrease of fractures, and restrict the high and stable production of shale oil and gas wells. The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section, forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface, strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid, optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.

Study on the Influence of Supercritical CO2 with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale.

Injection of carbon dioxide offers substantial social and economic advantages for reduction of carbon emission reduction. Utilizing CO2 in shale formations can significantly enhance the extraction of shale oil or gas. Conducting fundamental research on how CO2 affects shale rock's physical properties is crucial for enhancing its porosity and permeability. Particularly for deep shale layers, the effects of supercritical CO2 on shale physical properties should be investigated at a high temperature and pressure, differing from the standard conditions applied in shallower layers. A study examined the impact of supercritical CO2 under such conditions on the pore-throat structure and mineral composition of the shale. The experimental parameters included immersing shale rock in supercritical CO2 at pressures ranging from 10 to 70 MPa and temperatures between 55 and 95 °C. This study evaluated changes in mineral composition, pore-throat structure (using scanning electron microscopy and nitrogen adsorption tests), and the porosity and permeability of the shale rocks. Findings indicated that the dissolution of CO2 altered the relative content of certain minerals. The average quartz content rose and, potassium feldspar and the average contents of plagioclase declined conversely. When increasing the pressure, an increase in the relative content of I/S mixed layer and a decrease in illite content were observed and kaolinite content experienced minor changes. When increasing the temperature, kaolinite, I/S mixed layer, and chlorite all exhibited a decreasing trend with increasing temperature, while the relative contents of illite increased. Some of the pores become rounded in a high-magnification view under the impact of CO2 dissolution. Additionally, the Brunauer-Emmett-Teller specific surface area, pore volume, porosity, and permeability generally improved with increasing pressure and temperature. With the temperature and pressure of CO2 increased, the curves of nitrogen absorption had moved first upward and then downward. However, under specific CO2 conditions, the permeability enhancement effect could diminish or even negatively impact the shale's permeability. These findings underscore the need to optimize supercritical CO2 injection parameters under high-temperature and high-pressure conditions. This research aims to provide theoretical guidance for the efficient use of CO2 in deep shale applications to increase the shale gas output.

Experimental investigation of microscale mechanical alterations in shale induced by fracturing fluid contact

Understanding the changes in the mechanical properties of shale exposed to fracturing fluids is crucial for optimizing parameters in hydraulic fracturing. However, the dynamic alterations in mechanical properties still need to be disclosed due to the high heterogeneity of shale, particularly at the microscale. This paper aims to in-situ unravel the microscale changes in the dynamic mechanical properties of shale affected by fracturing fluids. A combination of nanoindentation, X-ray diffraction (XRD), scanning electron microscopy (SEM), and energy dispersive spectrum (EDS) techniques was employed. The nanoindentation results demonstrate a rapid initial decrease followed by a slower decline after 4 days in both Young's modulus and the hardness of shale exposed to fracturing fluids. Specifically, the average Young's modulus of shale ranges from 62.45 GPa to 56.275 GPa, 52.575 GPa, 40.15 GPa, and 39.5 GPa while the average hardness modulus varies from 3.305 GPa to 2.2125 GPa, 1.8175 GPa, 1.24 GPa and 1.1525 GPa with the treatment time of 0, 1, 2, 4, and 7 days, respectively. An exponential expression well describes the relationship between mechanical properties with the treatment time. XRD analysis shows carbonate and clay mineral content decrease, while quartz content increases. Moreover, in-situ SEM results highlight the emergence of many dissolution pores when shale is exposed to fracturing fluid. Further pH testing and EDS analysis indicates a corrosion effect, with hydrogen ions reacting with carbonate minerals in shale, leading to a significant reduction in calcite and dolomite. Consequently, the corrosion-induced dissolution pores weaken the stability of the shale matrix, leading to a reduction in mechanical properties. This study sheds light on the mechanism behind the dynamic mechanical properties of rock and provides valuable insights for optimizing the soaking time for fracturing fluids.

Determination of the Thickness and Fracture Toughness of Shale Interfacial Transition Zone Near Various Micromineral Aggregates Using Nano-Scratch Tests

Summary Heterogeneously distributed micromineral aggregates (MMAs) are common in shale reservoirs. The interfaces between these MMAs and the surrounding minerals significantly affect fracture propagation behaviors during shale oil exploitation. In this paper, the concept of interfacial transition zone (ITZ) between the MMAs (e.g., striped barite, pyrite, calcite, apatite blocks, and bedding plane) and the surrounding mineral in shale is introduced. Due to the small thickness of the ITZ, its thickness and mechanical properties are very difficult to determine by traditional standard methods. To address this issue, this paper proposes a method combining nano-scratch tests, scanning electron microscopy (SEM), and quantitative evaluation of minerals by SEM (QEMSCAN) techniques to investigate the thickness and fracture toughness of the ITZ near typical MMAs. The results show that the thickness of the ITZ determined by the transverse force FT and scratch depth (-d2) varies from 3.2 μm to 17.3 μm. In addition, the fracture toughness of both MMAs and ITZs is characterized by high heterogeneity ranging from 0.1 MPa·m0.5 to 2.1 MPa·m0.5. Moreover, a formula evaluating the fracture toughness of the ITZ is proposed taking into account the type and content of minerals in the ITZ. A strong linear relationship is observed between the thickness of the ITZ and the average fracture toughness ratio. In addition, a relationship is established between the fracture toughness of the ITZ and MMAs, and an evaluation equation is derived. This study is helpful for understanding the characteristics (i.e., mainly thickness and fracture toughness) of the ITZ within shales.