Longmaxi Shale Research Articles

Short-term interactions between Longmaxi shale and carbon dioxide-based fracturing fluids

The shale is a dense quarried rock material containing abundant shale oil/gas. Extracting shale gas usually requires fracturing the rock formation to speed up gas desorption and migration. Supercritical carbon dioxide fracturing, as an environmentally friendly and waterless fracturing technique of reservoir stimulation, gains increasing recognition in commercial exploitation of shale oil and gas. However, there is insufficient understanding on the interaction between carbon dioxide-based fracturing fluids and shale, as well as its influence on the mechanical parameters of shale, which are pivotal for determining injection parameters and forming the fracture network. This study focuses on the injection of carbon dioxide-based fracturing fluids to enhance shale gas extraction and carbon dioxide sequestration. Simulation tests of injection were conducted to investigate the influence of different fracturing fluids (deionized water, gaseous/supercritical carbon dioxide, gaseous/supercritical carbon dioxide mixed with brine) injected into shale reservoirs on the microstructure and mechanical properties of shale after short-term physicochemical interaction. This article adopts research methods such as uniaxial compression and uniaxial tensile mechanical experiments based on acoustic emission monitoring and various physical characterizations such as scanning electron microscopy, X-ray diffraction, X-ray fluorescence spectrometer, etc. Results show that following treatment with different carbon dioxide-based fluids, the uniaxial tensile/compressive strength, elastic modulus, fractal dimension of pore structure, and the brittleness index of shale exhibit varying degrees of decrease compared to those of dry untreated shale samples. After interacting with different carbon dioxide-based fracturing fluids, the mechanical parameters and brittleness index of shale decrease more significantly than that of the others as the addition of brine. This study shows that the water in carbon dioxide-based fracturing fluids is a controlling factor affecting the elastic modulus of shale. Additionally, the ductility of the shale increases and the acoustic emission emitting lag due to the coupling effects of brine and carbon dioxide. The change law of the elemental and mineral composition of the shale is consistent with the mechanical strength; and the change of element content and mineral composition is the most significant. Compared to gaseous carbon dioxide, the supercritical carbon dioxide has a greater impact on mineral composition of the shale. The change of mechanical strength and microstructure evolution mechanism caused by the short-term interactions between the shale and fracturing fluids provide theoretical references and implications for the determination of injection parameters and permeability transformation of the Longmaxi shale reservoirs.

Factors Controlling Differences in Morphology and Fractal Characteristics of Organic Pores of Longmaxi Shale in Southern Sichuan Basin, China

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments.

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.

Effects of CO2-saturated brine imbibition on the mechanical and seepage characteristics of Longmaxi shale

Supercritical carbon dioxide (SC– CO2) serves as a promising anhydrous fracturing fluid that has the potential to simultaneously enhance shale gas recovery and accomplish CO2 sequestration within shale reservoirs. However, the hydromechanical properties of shale are considerably affected by CO2-brine-shale interaction. This study conducted shale imbibition experiments involving subcritical/supercritical CO2 saturated brine (Sub/SC-CO2+brine). Triaxial compressive strength tests were performed to evaluate the impact of Sub/SC-CO2+brine imbibition on the mechanical properties of shale, as well as the influence of SC-CO2+brine imbibition on shale permeability. The results indicate that, after SC-CO2 brine imbibition, noticeable macroscopic cracks are formed parallel to the bedding plane. The imbibition of Sub/SC-CO2+brine results in the reduction in axial stress and Young's modulus, while simultaneously increasing the axial strain of shales. Compared to Sub-CO2+brine, SC-CO2+brine exhibits a higher imbibition pressure and a more intense geochemical reaction with shale. Due to increased compressibility sensitivity, the averaged permeability after SC-CO2+brine imbibition shows a reduction of nearly 70 % compared to that before imbibition. The insights from this research are expected to provide theoretical support for shale gas recovery and CO2 geological sequestration.

Mechanical degradation of Longmaxi shale exposed to water-based fluids and supercritical carbon dioxide

Mechanical alterations in shale formations due to exposure to water-based fracturing fluids and supercritical carbon dioxide (ScCO2) significantly affect the performance of shale gas exploration and CO2 geo-sequestration. In this study, a hydrothermal (HT) reaction system was set up to treat Longmaxi shale samples of varying mineralogies (carbonate-, clay-, and quartz-rich) with different fluids, i.e. deionized (DI) water, 2% potassium chloride (KCl) solution, and ScCO2 under HT conditions expected in shale formation. Statistical micro-indentation was conducted to characterize the mechanical property alterations caused by the shale-fluid interactions. An in situ morphological and mineralogical identification technique that combines scanning electron microscopy (SEM) and backscattered electron (BSE) imaging with energy-dispersive X-ray spectroscopy (EDS) was used to analyze the microstructural and mineralogical changes of the treated shale samples. Results show no apparent changes in the Young’s modulus, E, and hardness, H, after treatment with DI water under room temperature (20 °C) and atmospheric pressure for 7 d. In contrast, E and H were decreased by 31.2% and 37.5% at elevated temperature (80 °C) and pressure (8 MPa), respectively. The addition of 2% KCl into DI water mitigated degradation of the mechanical properties. Quartz-rich shale specimens are the least sensitive to the water-based fracturing fluids, followed by the clay-rich and carbonate-rich shale formations. Based on in situ morphological and mineralogical identification, the primary factors for the mechanical degradation induced by water-based fluids include carbonate dissolution, clay swelling, and pyrite oxidation. Slight increases in the measured E and H and compression of porous clay aggregates were observed after treatment with ScCO2. The major factor contributing to the mechanical changes resulting from the exposure to scCO2 appears to be the competition between swelling caused by adsorption and compression of shale matrix.

An assumed enhanced strain finite element framework for tensile fracturing processes with dual-mechanism failure in transversely isotropic rocks

We present an assumed enhanced strain finite element framework for the simulation of tensile fracturing processes in transversely isotropic rocks. Fractures along the weak bedding planes and through the anisotropic rock matrix are treated with distinct enrichment, and a recently proposed dual-mechanism tensile failure criterion for transversely isotropic rocks is adopted to determine crack initiation for the two failure modes. The cohesive crack model is adopted to characterize the response of embedded cracks. As for the numerical implementation of the proposed framework, both algorithms for the update of local history variables at Gauss points and of the global finite element system are derived. Four boundary-value problem simulations are carried out with the proposed framework, including uniaxial tension tests of Argillite, pre-notched square loaded in tension, three-point bending tests on Longmaxi shale, and simulations of tensile cracks induced by a strip load around a tunnel in transversely isotropic rocks. Simulation results reveal that the proposed framework can properly capture the tensile strength anisotropy and the anisotropic evolution of tensile cracks in transversely isotropic rocks.

Multifractal characteristics on pore structure of Longmaxi shale using nuclear magnetic resonance (NMR)

The efficient exploration and extraction of shale gas is essential for China's energy structure as a replacement for natural gas. In this research, shale samples from the Longmaxi Formation in Changning, Sichuan Province were investigated for their pore structure. To achieve this, X-ray diffraction (XRD) and nuclear magnetic resonance (NMR) experiments were performed on the samples. Fractal theory was employed to characterize the pore structure and fractal features of the shale reservoirs. The fractal characteristics of reservoir rocks were correlated with physical parameters and mineral components to identify the controlling factors for the multifractal dimension. The results indicate the following: ① Quartz predominates in the mineral composition of shale in the study area, while clay minerals are the least abundant. ② The primary pore types observed in the samples are bound fluid pores, primarily controlled by mesopores (2 nm ≤ r ≤ 50 nm). ③ The calculated multifractal parameters show that the heterogeneous pore structure exhibits multifractal characteristics. ④ The low probability multifractal parameters Dmin-D0 and αmax-α0 were found to be negatively correlated with reservoir porosity, permeability, and clay mineral content, while the high probability multifractal parameters D0-Dmax and α0-αmin were found to be positively correlated with them. The comprehensive fractal characterization of reservoir rocks demonstrates the applicability of multifractal dimensions in characterizing the heterogeneity of shale reservoir pore structures, which holds potential promise for coal methane exploration.

Molecular structure and evolution mechanism of shale kerogen: Insights from thermal simulation and spectroscopic analysis

During thermal evolution, the kerogen in shale formation undergoes significant chemical, structural and compositional changes, continuously influencing the shale storage capacity, hydrocarbon generation potential, and gas occurrence state. This study systematically examines the chemical structural changes during the thermal evolution of Longmaxi shale kerogen using hydrothermal laboratory experiments from 420 to 850 °C. Additionally, a range of characterization techniques, including Fourier Transform Infrared (FTIR) spectroscopy, Raman spectroscopy, High-Resolution Transmission Electron Microscopy (HRTEM), X-ray Diffraction (XRD), and Solid-state 13C Nuclear Magnetic Resonance (13C NMR), were employed to systematically investigate the kerogen structure and its evolution patterns. Results indicate that Longmaxi Formation kerogen comprises a large molecular carbon framework with aromatic structures, long-chain aliphatic components, and oxygen-containing functional groups. As thermal maturity reaches 2.6 %, the alignment of aromatic fringes gradually increased, with over 60 % aligning in the main direction. Throughout thermal evolution (1.9–3.2 %), fringes in the 5–10 Å range within aromatic structures peak at over 20.45 %, with fringes over 50 Å rapidly increasing from 3 % to over 15 %. Early in the thermal evolution, the long-chain aliphatic component of the kerogen decreases rapidly and part of the structure forms small aromatic rings through aromatisation. The mature to over-mature stage can be divided into three phases: 1) 1.7–2.4 % (loss of oxygen-containing functional groups), 2) 2.4–3.5 % (formation of larger aromatic structures via condensation reactions), 3) over 3.5 % (continued aggregation of aromatic rings, resulting in an increase in the length of aromatic fringes). At a macroscopic level, this induces changes in kerogen pore structure and carbonization features. This study thus provides new insights into the thermal evolution of shale kerogen, which in turn improve understanding of shale reservoirs for hydrocarbon exploitation.

Provenance composition and evolution of marine black shales in the Yangtze platform from Ediacaran to Silurian

Provenance is important in understanding the evolution of geological structure and the coupling of the basin-mountain system. Although many geochemical data document the three sets of marine black shales (Ediacaran to Silurian) in the Yangtze Platform, the evolution characteristics of their sediment sources remain unclear. We gather a huge database from 307 published papers totaling 12,342 analyzed samples to establish provenance. Pearson correlation coefficient and multivariate statistical analyses were performed to establish the element and mineral links in the black shale. Nine immobile elemental ratios (Ti/Th, Th/Sc, Cr/Th, Ti/Zr, Sc/Ta, Ti/Nb, Sc/La, Zr/Sc, and La/Ti) were employed to indicate provenance. The results show that the black shales of the Longmaxi and Niutitang formations are relatively enriched in redox sensitive and productivity related elements such as V, Cr, Mo, U, Co, Ni, Cu, Zn, and Ba. The use of provenance analysis proxies, including V, Cr, Mo, Ce, Fe, P, Ba, Cu, Ni, and Si, should be approached with caution due to the potential interference of marine authigenic components. The three black shales have provenance compositions that gradually extend from intermediate to felsic from the Doushantuo to the Niutitang to the Longmaxi shale. This difference in provenance is a response to the Pan-African and Kwangsian orogenic structures which are likely to impact the paleomarine environment by variable biotrophic element inputs.

Adsorption and Diffusion Properties of Gas in Nanopores of Kerogen: Insights from Grand Canonical Monte Carlo and Molecular Dynamics Simulations

Investigating the adsorption and diffusion processes of shale gas within the nanopores of kerogen is essential for comprehending the presence of shale gas in organic matter of shale. In this study, an organic nanoporous structure was constructed based on the unit structure of Longmaxi shale kerogen. Grand canonical Monte Carlo and molecular dynamics simulation methods were employed to explore the adsorption and diffusion mechanisms of pure CH4, CO2, and N2, as well as their binary mixtures with varying mole fractions. The results revealed that the physical adsorption characteristics of CH4, CO2, and N2 gases on kerogen adhered to the Langmuir adsorption law. The quantity of adsorbed gas molecules increased with rising pressure but decreased with increasing temperature. The variation in the heat of adsorption was also analyzed. Under identical temperature and pressure conditions, the adsorption of CH4 increased with higher mole fractions of CH4, whereas it decreased with greater mole fractions of CO2 and N2. Notably, CO2 molecules exhibited a robust interaction with kerogen molecules compared to the adsorption properties of CH4 and N2. Furthermore, the self-diffusion coefficient of gas within kerogen nanopores gradually decreased with increasing pressure or decreasing temperature. The diffusion capacity of gas molecules followed the descending order N2 > CH4 > CO2 under the same pressure and temperature conditions.

Frictional process, AE characteristics, and permeability evolution of rough fractures on Longmaxi shale with specific roughness under water injection

Studying the frictional process, acoustic emission (AE) characteristics and permeability evolution of fractures under water injection is fundamental for proposing theories and methods to control the stability of geological structures. In this work, the shear-flow test was conducted on Longmaxi shale fractures with different specific roughness to analyze the frictional deformation and mechanical properties of shale fractures during the frictional slip process, and the influence of effective normal stress and surface morphology was investigated. AE monitoring technology was also utilized to reveal the AE evolution during the frictional slip process. Based on the AF/RA values, AE signals were subjected to cluster analysis using the Gaussian Mixture Model (GMM) to distinguish and quantify the crack types and proportions during frictional slip. Combining the development of cracks and considering the ratio of worn area, a theoretical analytical expression was established to reasonably describe the friction-damage evolution, classifying the friction-damage during the frictional slip process into tensile and shear damage, respectively. Meanwhile, the permeability evolution of Longmaxi shale fractures was also studied in detail. A theoretical model capable of describing and predicting the permeability evolution was proposed under the condition that the permeability evolution and damage process of Longmaxi shale fractures correspond to each other. Finally, the interaction between asperities on shale fractures with different surface morphologies during the frictional slip process was discussed, and the influence mechanism of surface morphology on permeability evolution was revealed.

Characterization of brittleness index of gas shale and its influence on favorable block exploitation in southwest China

The microstructure, mineral composition, total organic carbon content, etc., of gas shale are crucial parameters for shale reservoirs, which can directly/indirectly affect shale brittleness, fracturing effect, adsorption ability and production efficiency. The study proposed a workflow to characterize the physical and mechanical parameters of Lower Silurian Longmaxi shale outcrop samples extracted from the favorable block in Changning, Sichuan, southwest China. This study elaborated on the influence of these physical and mechanical characteristics and proposed a corresponding brittleness index on shale extraction. In addition, it put forward corresponding suggestions for development and risk control. For a better understanding the mechanisms of shale gas storage and production, XRD, XRF, SEM, low temperature Nitrogen adsorption method, nuclear magnetic resonance and other measurements were employed to analyze and study the mineral composition, microstructure, and adsorption performance of shale. The results demonstrated that the pores of shale are mainly slit pores; there are diverse pore types in shale, mainly including intergranular pores, mineral particle dissolution pores, and internal pores of organic matter; The samples with relatively low porosity also noticeably exhibit ultra-low permeability, and the nanopore structure is remarkably significant, with distribution primarily in range of 5–237 nm. Finally, a brittleness index considering the influence of water content and the mechanical properties was proposed, and the coupling interaction of various minerals components and mechanical properties on the brittleness index can more objectively reflect the brittleness characteristics of deep shale formation.

Geomechanical characterization and mineralogical correlation of compositionally diverse world-class Kazakhstani source rocks: Insights from nanoindentation testing

Extensive nanoindentation testing over a range of deflection depths of up to 4 μm yielded a large dataset, providing a viable framework for the statistical assessment of the mechanical properties, specifically elastic modulus (E) and hardness (H), of compositionally diverse organic-rich mudstone samples. The data from indentations as shallow as 300–400 nm were clustered using the k-means algorithm to identify three mechanical categories in the samples: a soft pseudophase (e.g., organic matter, gypsum, and clay minerals), a stiff pseudophase (e.g., quartz and feldspar), and a transitional composite-like pseudophase bridging the soft and hard minerals. The initially diverse values of E and H for the mechanical pseudophases were observed to converge to a constant value at indentations beyond 2–2.5 μm (varying between different samples), implying the existence of a minimal probing depth for assessing the bulk E and H of heterogeneous mudstone samples. The obtained bulk E and H values (8–21 GPa and 0.3–0.9 GPa, respectively) demonstrated a strong correlation with the mineralogical composition of the indented samples. Despite containing a notable proportion of mechanically stiff components (>45 vol%), the bulk mechanical parameters determined in this study were significantly lower than those reported for major shale formations such as the Barnett and Longmaxi Shale. This discrepancy is primarily due to the presence of organic matter with low thermal maturity (Ro < 0.6%), which constitutes <36 vol% of the samples, and a significant gypsum content, accounting for <15 vol%.The employed approach not only demonstrated the importance of choosing the proper indentation depths for investigating the mechanical properties of highly heterogeneous mudstone rocks and their constituent minerals, but it also illustrated the capability of examining various volumes of investigation using nanoindentation, approaching macroscopic values, and identifying a representative element volume (REV). The findings also provided crucial insights into the fracability and overall producibility of the investigated formations, thereby enhancing our understanding of their extraction potential.

Thermomechanical coupling seepage in fractured shale under stimulation of supercritical carbon dioxide

As a waterless fracturing fluids for gas shale stimulation with low viscosity and strong diffusibility, supercritical CO2 is promising than the water by avoiding the clay hydration expansion and reducing reservoir damage. The permeability evolution influenced by the changes of the temperature and stress is the key to gas extraction in deep buried shale reservoirs. Thus, the study focuses on the coupling influence of effective stress, temperature, and CO2 adsorption expansion effects on the seepage characteristics of Silurian Longmaxi shale fractured by supercritical CO2. The results show that when the gas pressure is 1–3 MPa, the permeability decreases significantly with the increase in gas pressure, and the Klinkenberg effects plays a predominant role at this stage. When the gas pressure is 3–5 MPa, the permeability increases with the increase in gas pressure, and the influence of effective stress on permeability is dominant. The permeability decreases exponentially with the increase in effective stress. The permeability of shale after the adsorption of CO2 gas is significantly lower than that of before adsorption; the permeability decreases with the increase in temperature at 305.15 K–321.15 K, and with the increase in temperature, the permeability sensitivity to the temperature decreases. The permeability is closely related to supercritical CO2 injection pressure and volume stress; when the injection pressure of supercritical CO2 is constant, the permeability decreases with the increase in volume stress. The results can be used for the dynamic prediction of reservoir permeability and gas extraction in CO2-enhanced shale gas development.

Characteristics and Controlling Factors of Methane Adsorption of the Longmaxi Shale in Northeastern Chongqing: Implications for Shale Gas Occurrence in Complex Structural Areas

Characteristics and Controlling Factors of Methane Adsorption of the Longmaxi Shale in Northeastern Chongqing: Implications for Shale Gas Occurrence in Complex Structural Areas

Formation and evolution of shale overpressure in deep Wufeng-Longmaxi Formation in southern Sichuan basin and its influence on reservoir pore characteristics

In the deep Longmaxi Formation shale gas reservoirs of the southern Sichuan Basin, strong overpressure is universally developed to varying degrees. However, there is currently a lack of in-depth research on the formation mechanisms, evolutionary patterns, and the controlling effects on reservoir pore characteristics of strong overpressure. This limitation significantly restricts the evaluation of deep shale gas reservoirs. This study selected typical overpressured shale gas wells in Yongchuan, Luzhou, and Dazu areas as research subjects. Through comprehensive methods such as log analysis, fluid inclusion analysis, and numerical simulation, the dominant mechanisms of strong overpressure formation were determined, and the pressure evolution from early burial to late strong uplift was characterized. Additionally, the impact of varying degrees of overpressure on reservoir pore characteristics was studied using techniques such as scanning electron microscopy, gas adsorption-mercury intrusion, and helium porosity testing. The research findings indicate that hydrocarbon generation expansion is the primary mechanism for strong overpressure formation. The pressure evolution in the early burial phase is controlled by the processes of kerogen oil generation and residual oil cracking into gas. The reservoir experienced three stages: normal pressure (Ordovician to Early Triassic), overpressure (Early Triassic to Early Jurassic), and strong overpressure (Early Jurassic to Late Cretaceous), with pressure coefficients of approximately 1.08, 1.56, and 2.09, respectively. During the late strong uplift phase, the adjustment of early overpressure occurred due to temperature decrease and gas escape, leading to a decrease in formation pressure from 140.55 MPa to 81.63 MPa, while still maintaining a state of strong overpressure. Different degrees of strong overpressure exert a significant control on the physical properties of shale reservoirs and the composition of organic matter pores. Variations exist in the organic matter pore morphology, structure, and connectivity within the deep Wufeng-Longmaxi shale. Higher overpressure favors the preservation of organic large pores and reservoir porosity. Under conditions of strong overpressure development, deep siliceous shales and organically rich clay shales exhibit favorable reservoir properties. By determining the dominant mechanisms of strong overpressure in the Wufeng-Longmaxi Formation and studying pore characteristics, this research not only deepens the understanding of the geological features of deep shale gas reservoirs but also provides a new perspective for understanding the overpressure mechanisms and reservoir properties of deep shale gas reservoirs. Moreover, it is of significant importance for guiding the exploration and development of deep Longmaxi shale and provides valuable references for further research in related fields.

Frictional Stability and Permeability Evolution of 3D Carved Longmaxi Shale Fractures and Its Implications for Shale Fault Stability in Sichuan Basin

Frictional Stability and Permeability Evolution of 3D Carved Longmaxi Shale Fractures and Its Implications for Shale Fault Stability in Sichuan Basin

Effect of height-diameter ratio on the mechanical characteristics of shale with different bedding orientations

Geological exploration cores obtained from shale gas wells several kilometers deep often show different height-diameter ratios (H/D) because of complex geological conditions (core disking or developed fractures), which makes further standard specimen preparation for mechanical evaluation of reservoirs difficult. In multi-cluster hydraulic fracturing, shale reservoirs between planes of hydraulic fractures with different lengths could be simplified to have different H/D ratios. Discovering the effect of H/D on the mechanical characteristics of shale specimens with different bedding orientations will support mechanical evaluation tests of reservoirs based on disked geological cores and help to optimize multi-cluster fracturing programs. In this study, we performed uniaxial compression tests and acoustic emission (AE) monitoring on cylindrical Longmaxi shale specimens under five bedding orientations and four H/D ratios. The experimental results showed that both the H/D-dependent mechanical properties and AE parameters demonstrated significant anisotropy. Increasing H/D did not change the uniaxial compressive strength (UCS) evolution versus bedding orientation, demonstrating a V-shaped relationship, but enhanced the curve shape. The stress level of crack damage for the specimens significantly increased with increasing H/D, excluding the specimens with a bedding orientation of 0°. With increasing H/D, the cumulative AE counts of the specimens with each bedding orientation tended to exhibit a stepped jump against the loading time. The proportion of low-average-frequency AE signals (below 100 kHz) in specimens with bedding orientations of 45° and 60° increased to over 70% by increasing H/D, but it only increased to 40% in specimens with bedding orientations of 0°, 30°, and 90°. Finally, an empirical model that can reveal the effect of H/D on anisotropic UCS of shale reservoir was proposed, the anisotropic proportion of tensile and shear failure cracks in specimens under four H/D ratios was classified based on the AE data, and the effect of H/D on the anisotropic crack growth of specimens was discussed.

Adsorption and Desorption Behavior of Partially Hydrolyzed Polyacrylamide on Longmaxi Shale

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30 °C and 800 mg/L when the aqueous solution temperature was 60 °C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30 °C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60 °C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order (PSO) kinetics model yielded better fits than the pseudo-first order (PFO) kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption was able to resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb and the easier it was to be removed from the shale.

Research of water influence on macro and homogenized fracture toughness, brittleness and relationship between different mechanical properties of Longmaxi shale outcrop

For better understanding the water influence on shale mechanical characteristics, chip, column, powder and semi-circular bend four types of shale sample from Longmaxi outcrop processed to 5 different moisture degree, are prepared to separately conduct SEM observation for in-situ location after processing, AFM test and nanoindentation for data of fracture toughness calculation, uniaxial/triaxial compression test for internal friction angle, nitrogen adsorption test for pore volume, SCB test for macro fracture toughness. An improved Energy-based method is proposed to calculate micro fracture toughness based on results from AFM test, in comparison with micro fracture toughness calculated with energy method and nanoindentation curves, the results of improved energy-based method are acceptable. By analogy with elastic modulus, a new method is proposed to calculate macro fracture toughness changing ratio with rising saturation based on micro fracture toughness computed with AFM test data including maximum force, maximum depth, contact area, hardness and elastic modulus. This method can be applied to computing macro brittleness changing ratio based on micro brittleness calculated with AFM test data, its changing pattern fits the pattern of brittleness computed by internal friction angle. Unlike fracture toughness getting down consistently, shale brittleness gets down initially then climbs up with rising saturation. But average value cannot represent macro level, the linear relationship between fracture toughness and Young's modulus disappears due to moisture influence. A comparative analysis between nanoindentation and AFM is conducted from three aspects, AFM is a better method to detect micro mechanical properties influenced by some factor at different degree.