Pore Structure Of Shale Research Articles

Experimental investigation on pyrolysis products and pore structure characteristics of organic-rich shale heated by supercritical carbon dioxide

The efficient pyrolysis and conversion of organic matter in organic-rich shale, as well as the effective recovery of pyrolysis shale oil and gas, play a vital role in alleviating energy pressure. The state of carbon dioxide (CO2) in the pyrolysis environment of shale reservoirs is the supercritical state. Its unique supercritical fluid properties not only effectively heat organic matter, displace pyrolysis products and change shale pore structure, but also achieve carbon storage to a certain extent. Shale samples were made into powder and three sizes of cores, and nitrogen (N2) and supercritical carbon dioxide (ScCO2) pyrolysis experiments were performed at different final pyrolysis temperatures. The properties and mineral characteristics of the pyrolysis products were studied based on gas chromatography analysis, X-ray diffraction tests, and mass spectrometry analysis. Besides, the pore structure characteristics at different regions of cores before and after pyrolysis were analyzed using N2 adsorption tests to clarify the impact of fracturing degree on the pyrolysis effect. The results indicate that the optimal pyrolysis temperature of Longkou shale is about 430 °C. Compared with N2, the oil yield of ScCO2 pyrolysis is higher. The pyrolysis oil obtained by ScCO2 extraction has more intermediate fractions and higher relative molecular weight. The ScCO2 can effectively improve the pore diameter of shale and its effect is better than that of N2. The micropores are produced in shale after pyrolysis, and the macropores only are generated in ScCO2 pyrolysis environments with temperatures greater than 430 °C. The pore structure has different development characteristics at different pyrolysis temperatures, which are mainly affected by the pressure holding of volatile matter and products blocking. Compared to the surface of the core, the pore development effect inside the core is better. With the decrease in core size, the pore diameter, specific surface area, and pore volume of cores all increase after pyrolysis.

Quantitative characterization of organic and inorganic pores in shale based on deep learning

Organic matter (OM) maturity is closely related to organic pores in shales. Quantitative characterization of organic and inorganic pores in shale is crucial for rock-physics modeling and reservoir porosity and permeability evaluation. Focused ion beam-scanning electron microscopy (FIB-SEM) can capture high-precision three-dimensional (3D) images and directly describe the types, shapes, and spatial distribution of pores in shale gas reservoirs. However, due to the high scanning cost, wide 3D view field, and complex microstructure of FIB-SEM, more efficient segmentation for the FIB-SEM images is required. For this purpose, a multiphase segmentation workflow in conjunction with a U-net is developed to segment pores from the matrix and distinguish organic pores from inorganic pores simultaneously in the entire 3D image stack. The workflow is repeated for FIB-SEM data sets of 17 organic-rich shales with various characteristics. The analysis focuses on improving the efficiency and relevance of the workflow, that is, quantifying the minimum number of training slices while ensuring accuracy and further combining the fractal dimension (FD) and lacunarity to study a simple and objective method of selection. Meanwhile, the computational efficiency, accuracy, and robustness to noise of the 2D U-net model are discussed. The intersection over the union of automatic segmentation can amount to 80%–95% in all data sets with manual labels as ground truth. In addition, calculated by the FIB-SEM multiphase segmentation, the organic porosity is used to quantitatively evaluate the OM decomposition level. Deep-learning-based segmentation shows great potential for characterizing shale pore structures and quantifying OM maturity.

Study of the influence of pore structure on the radon emission characteristics of terrestrial sedimentary shales after high temperature action.

Heat-assisted development of shale oil and gas is recognized as a vital technique for the efficient extraction of shale gas; however, there is a need for comprehensive investigation regarding radon release during the extraction process. The aim of this study was to investigate the pore structure and radon release characteristics of heat-treated black shale using low-temperature nitrogen adsorption (LTNA) and radon (Rn-222) measurement equipment. The findings reveal that temperature initially enhances radon release, which subsequently decreases. The maximum radon release occurs at 500 °C, reaching 1.46 times the initial stage. The radon release rate is positively correlated with the volume of micropores (< 2 nm) in the shale. Organic pores within the shale serve as the primary storage spaces for radon, and the intricate pore structure of organic matter provides an optimal environment for radon gas retention. These results contribute to elucidating the mechanisms behind the impact of thermal treatment on shale's radon release rate, which is crucial for guiding radon radiation evaluation in thermal treatment processes.

Pore Structure and Migration Ability of Deep Shale Reservoirs in the Southern Sichuan Basin

The migration phenomenon of deep shale gas is a subject that has yet to be fully comprehended, specifically regarding the migration ability of deep shale gas. This study focuses on the Longmaxi Formation in the southern Sichuan Basin, utilizing it as an example. Various experimental techniques, such as temperature-driven nitrogen and carbon dioxide adsorption, high-pressure mercury intrusion, XRD, and TOC analysis, are employed. The goal is to analyze the pore structure and fractal characteristics of the Longmaxi Formation shale. Additionally, the study aims to calculate its Knudsen number based on parameters like temperature gradient and pressure coefficient. The migration ability of the Longmaxi Formation shale in southern Sichuan Basin is also discussed. The results show the following: (1) The pore volume distribution of the Longmaxi Formation shale in the study area ranges from 0.0131 to 0.0364 cm3/g. Mesopores contribute approximately 56% of the pore volume, followed by micropores with a contribution rate of about 26%, and macropores contributing approximately 18%. Additionally, the Longmaxi Formation shale exhibits strong heterogeneity, with the fractal dimension (D1) of mesopores ranging from 2.452 to 2.8548, with an average of 2.6833, and the fractal dimension (D2) of macropores ranging from 2.9626 to 2.9786, averaging 2.9707. (2) The fractal dimensions of shale were significantly influenced by organic matter, inorganic minerals, and pore structure parameters. D1 and D2 were positively correlated with TOC, clay mineral content, and specific surface area, while exhibiting negative correlation with quartz. However, the correlations with calcite content, pore volume, and average pore size were not significant. (3) The proportion of pores satisfying Darcy flow in the Longmaxi Formation shale was approximately 3.7%–11.8%, with an average of 6.6%. Consequently, the migration capability of shale gas can be calculated using Darcy’s law. Furthermore, the migration capability of shale gas is controlled by D2, specifically the surface area, and the connectivity of macropores.

A novel apparent permeability model for shale considering the influence of multiple transport mechanisms

Changes in pore pressure during the extraction of shale gas lead to dynamic alterations in the pore structure and permeability, making it challenging to gain a comprehensive understanding of the flow behaviors of shale gas. The pore structure of shale is complex, with a variety of storage modes and gas transport processes constrained by a number of factors. For instance, when gas flows through a transport channel with a finite length, it is imperative to take into account the flow loss caused by the bending of inlet and outlet streamlines, prior models typically neglect the impact of end effects, resulting in an exaggerated estimation of the shale permeability. Furthermore, a decrease in pore pressure corresponds to an increase in the Knudsen number, resulting in the breakdown of the continuity assumption of the Navier–Stokes equation, this signifies the gradual shift of the transport regimes from continuum flow to other transport regimes. The gas flow process is nonlinear due to the alternating impact of multicomponent transport mechanisms and various microscale effects. In this paper, we presented a novel apparent permeability model for shale that incorporates the impact of real gas effect, end effects, transport regimes, adsorption, and effective stress. First, we assumed the channel for shale gas transport to be circular pore and calculated the viscosity under the influence of a real gas effect as well as the corresponding Knudsen number. Subsequently, building upon the foundation of the slip model, we introduce the influence of the end effects to establish a bulk phase permeability for shale, further considering the impact of surface diffusion. Then, the pore radius was quantified under the influences of adsorption and effective stress. Using the intrinsic correlation between permeability and pore radius as a bridge, a shale apparent permeability model was further derived. The model encompasses various transport regimes and microscale effects, replicating the gas flow behaviors in shale. The new model was verified through comparison with published experimental data and other theoretical models, while analyzing the evolution of apparent permeability. Additionally, this paper discusses the influence of various factors, including end effects, pore radius, internal swelling coefficient, sorption-induced strain, and model-related parameters on the shale apparent permeability.

Ultrahigh-Resolution Reconstruction of Shale Digital Rocks from FIB-SEM Images Using Deep Learning

Summary Accurate characterization of shale pore structures is of paramount importance in elucidating the distribution and migration mechanisms of fluids within shale rocks. However, the acquisition of high-resolution (HR) images of shale rocks is limited by the precision of the scanning equipment. Even with higher-precision devices, compromising the image field of view becomes inevitable, making it challenging to faithfully represent the actual conditions of shale. We propose a stepwise 3D super-resolution (SR) reconstruction method for shale digital rocks based on the widely used focused-ion-beam scanning electron microscope (FIB-SEM) technique. This method effectively addresses the issues of inconsistent horizontal and vertical resolutions as well as low 3D image resolution in FIB-SEM images. By adopting this approach, we significantly enhance image details and clarity, enabling successful observations of pores smaller than 10 nm within shale and laying a foundation for further pore-scale flow simulations. Furthermore, we extract the pore network model (PNM) from the SR reconstructed digital rock to analyze the pore size distribution, coordination number, and pore-throat ratio of shale samples from the Jiyang Depression. The results demonstrate a pore radius distribution in the range of 0 nm to 40 nm, which aligns with the results from nitrogen adsorption experiments. Notably, pores with radii smaller than 10 nm account for 50% of the total connected pores. The proportion of isolated pores in the SR reconstructed shale PNM is significantly reduced, with the coordination number mainly distributed between 1 and 4. The pore-throat ratio of shale ranges from 1 to 3, indicating a relatively uniform development of pores and throats. This study introduces a novel method for accurately characterizing the shale pore structure, which aids researchers in evaluating the pore size distribution and connectivity of shales.

Shale primary porosimetry based on 2D nuclear magnetic resonance of T1-T2

Porosity, a key parameter in assessing the physical properties of shale reservoirs and the reserves, is of great significance to the selection and evaluation of shale sweet spots. There are many methods at present to characterize shale porosity, most of which are aimed at post-core cleaning shale, such as those involving helium and saturated fluid (namely liquid-involved porosimetry). However, due to the low efficiency of shale core cleaning and the possible damage to pore structure during the core cleaning process, it's hard to guarantee the accuracy of porosity measurement. In this regard, we resort to the two-dimensional (2D) nuclear magnetic resonance (NMR) technology of T1-T2 in characterizing the primary shale porosity with samples taken from pressure coring in the 4th member of Shahejie Formation (Sha 4 Member) in well Fanxie 184 in the Jiyang Depression. Moreover, comparative experiments of shale porosity measurement by three methods, namely the simultaneous distillation extraction (SDE), helium and fluid measurement, are carried out simultaneously. The results show that the values obtained by SDE, gas and liquid measurement are similar, which are about 0.6 times of 2D NMR porosimetry. Core cleaning efficiency tends to seriously affect the results involving gas and liquid. In addition, the core cleaning treatment is bound to change the shale pore structure, and this is especially true in clay which tends to swell; consequently, porosity results are to be distorted by gas and liquid methods. It is thereby recommended to utilize the 2D NMR technology to characterize the primary total porosity of shale samples without core cleaning. The effective porosity of samples from pressure coring is determined by T2 cutoff value of around 0.3 ms.

Pore Structure and Fractal Characteristics of Coal Measure Shale in the Wuxiang Block in the Qinshui Basin

To study the fractal characteristics of the pore structure and the main controlling factors of coal measure shale in the Wuxiang block in Qinshui Basin, gas adsorption (CO2 and N2), mercury intrusion porosimetry (MIP), total organic carbon (TOC) content, and X-ray diffraction (XRD) experiments were carried out. The fractal dimensions of the micropores, mesopores, and macropores were computed by combining the V-S, FHH, and MENGER models. The results show that the fractal dimension increases with the increase in pore size; so, the macropore structure is the most complex. The effects of the TOC content, mineral fractions, and pore structure on the fractal dimensions were analyzed. The results showed that the TOC content certainly correlated with the mesopore fractal dimension, and the R2 is 0.9926. The pore volume and specific surface area show an obvious positive correlation with the macroporous fractal dimension, and their R2 values are 0.6953 and 0.6482, indicating that the macroporous pore structure of coal shale in the study area is more complex. There is a significant positive correlation between kaolinite and the macropore fractal dimension, and the R2 is 0.7295. Therefore, the organic carbon and kaolinite contents and the pore structure parameters are the most important factors affecting the fractal dimension characteristics.

Thermal behavior of minerals in shale and its influence on evolution of gas-flow channels under thermal shock

Thermal shock-induced damage can significantly enhance the connectivity of the rock's fracture network. Thermal Enhanced Recovery (TER) technology holds promising potential for application in shale gas production. Nevertheless, there is still a lack of direct experimental studies focusing on the evolution of shale's gas-flow channels and the mechanism of thermal fracturing in shale under the influence of thermal shock. In this study, we initially investigated the impact of thermal shock on various minerals in shale through X-ray diffraction (XRD) analysis and scanning electron microscope (SEM) imaging, and examined the mass and heat variation with temperature using Thermogravimetry-Differential Scanning Calorimetry (TG-DSC) testing. Subsequently, we assessed the alterations in shale's internal structure due to thermal shock through low-temperature gas (N2) adsorption (LTGA) analysis, and observed the distribution and expansion patterns of shale fractures under thermal shock using computed tomography (CT). Finally, we evaluated the changes in shale permeability before and after thermal shock. The findings indicate that quartz, feldspar, and clay exhibit relatively stable behavior in shale under thermal shock, whereas carbonate and pyrite are prone to crack. Under the combined influence of mineral cracking and thermal stress, the internal pore structure of shale tends to enlarge in size while reducing in surface area. The substantial decrease in pore specific surface area highlights the considerable reduction in gas adsorption capacity. Furthermore, fractures expand along the bedding planes as surface fractures. The expansion of pores and fractures promotes the formation of primary gas-flow channels. In addition, the aforementioned test results demonstrate a high level of consistency, specifically highlighting a distinct threshold temperature (500 °C) for the alteration of various physical parameters of shale during thermal shock. This study is anticipated to offer insights into the implementation of TER technology in the oil and gas industry.

A Study on the Pore Structure and NMR Fractal Characteristics of Continental Shale in the Funing Formation of the Gaoyou Sag, Subei Basin

The continental shale oil resource in China exhibits significant potential and serves as a crucial strategic alternative to the country’s conventional oil and gas reserves. The efficacy of shale oil exploration and production is heavily contingent upon the heterogeneity of the pore structure within the reservoir. However, there remains a scarcity of research pertaining to the pore structure of continental shale and the factors that influence it. The objective of this study is to provide a quantitative characterization of the heterogeneity exhibited by the continental shale of the Funing Formation in the Gaoyou Sag. In this study, the research focus is directed toward the continental shale of the Funing Formation located in the Gaoyou Sag of the Subei Basin. This paper examines the correlation between the fractal dimension of nuclear magnetic resonance (NMR) and various factors including the total organic carbon (TOC), mineral composition, geochemical parameters, and physical properties, utilizing the principles of fractal dimension theory. The findings indicate that the primary pore types observed in the Funing Formation continental shale are inorganic matrix pores, which encompass dissolution pores, clay mineral intergranular pores, and a limited number of pyrite intergranular pores. By employing a relaxation time cutoff, the NMR fractal dimension can be categorized into two distinct dimensions: the bound-fluid-pore fractal dimension (0.5795~1.3813) and the movable-fluid-pore fractal dimension (2.9592~2.9793). The correlation between mineral composition and the fractal dimension indicates a negative relationship between the fractal dimensions of bound-fluid pores and movable-fluid pores and the content of quartz. The correlation between clay minerals and the fractal dimension indicates a significant negative relationship between the fractal dimensions of bound-fluid pores and movable-fluid pores with illite. There exists a negative correlation between the pore fractal dimension of bound fluid and the content of organic matter, whereas a positive correlation is observed between the pore fractal dimension of mobile fluid and the content of organic matter. The range of maturity of organic matter within the Funing Formation exhibits a relatively limited span, as indicated by the vitrinite reflectance (Ro) values falling between 0.8% and 0.9%. This narrow range of maturity does not exert a substantial influence on the two fractal dimensions. The NMR fractal dimension exhibits a negative correlation with permeability in relation to reservoir physical properties, while the bound-fluid-pore fractal dimension demonstrates a negative correlation with the total porosity. The findings suggest that the NMR fractal dimension can serve as a valuable indicator for evaluating the physical characteristics of reservoirs. The present study successfully examined the pore structure of continental shale through the utilization of nuclear magnetic resonance technology. This innovative technique provides a novel avenue for the assessment of continental shale reservoirs and the investigation of pore heterogeneity on a global scale.

Methane adsorption effected by pore structure of overmature continental shale: Lower Cretaceous Shahezi Formation, Xujiaweizi Fault, Songliao Basin

Methane adsorption effected by pore structure of overmature continental shale: Lower Cretaceous Shahezi Formation, Xujiaweizi Fault, Songliao Basin

Pore structure and gas adsorption characteristics in stress-loaded shale on molecular simulation

Since stress from overlying strata is one of the primary factors influencing pore structure and gas content in shale reservoirs, understanding its role is crucial for developing shale gas fields. In this study, Molecular Mechanics and Molecular Dynamics methods were employed to investigate the intrinsic relationship between pore structure, energy, and adsorption performance of the organic matter matrix under different stress conditions. The results show that the pore structure of the organic matrix can be categorized into three stages with the variation of external stress, with 0.2 and 0.8 GPa as the boundaries. The effect of external stress significantly impacts the methane adsorption capacity in the organic matrix. Changes in stress not only result in a reduction of adsorption space but also an increase in adsorption sites. These two factors have opposite effects on CH4 adsorption in the model. That is, the negative impact of the reduction in adsorption space outweighs the positive impact of the increase in adsorption sites, resulting in a decrease in the adsorption capacity. At 0.8 and 1 GPa, the maximum CH4 adsorption capacity was reduced by 70 % and 58 %, respectively. This study provides an important reference for understanding the pore structure of the organic matrix and the adsorption characteristics of CH4 in shale gas reservoirs.

Evolution of organic pores in Permian low maturity shales from the Dalong Formation in the Sichuan Basin: Insights from a thermal simulation experiment

Shale oil and gas exploration is greatly impacted by the development and evolution of organic pore structures. In order to study the evolution of shale pore structures over maturities, we conducted thermal simulation experiments on low-mature organic-rich shale (Ro = 0.73%, TOC = 9.57%) obtained from the Dalong Formation. Various maturity stages were covered in these experiments, from low to over-maturity. By analyzing mineral composition, organic geochemistry, and characteristics of pore structures at various temperatures used for thermal simulation, we examined how organic matter pores generate and evolve during the formation of shale hydrocarbons. As a result, an integrated model of the evolution of pore structures in organic-rich shale was developed. Our study revealed the following insights: With increasing thermal simulation temperature, shale pore development exhibited three distinct stages: initial development, rapid development, and slow development. These stages correspond respectively to the three stages of organic matter thermal evolution. The distribution of pores in the shale transitioned from a unimodal structure dominated by larger pores to a bimodal structure with both micropores and macropores. Decomposition of organic matter and pressure compaction play a controlling role on organic porosity. Pore structure parameters and fractal dimensions of the pores were primarily influenced by organic matter decomposition, residual liquid hydrocarbons, and diagenetic processes. Additionally, kerogen type, morphology of organic matter debris, symbiosis of minerals-organic matter also impacted pore development.

Investigation of the Effect of Fracturing Fluids on Shale Pore Structure by Nuclear Magnetic Resonance

Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology was utilized to conduct high-pressure soaking tests on shale specimens treated with EM30+ + guar gum mixed water and CNI nano variable-viscosity slickwater, where various concentrations of a drag reducer were utilized. Additionally, the differences in porosity, permeability, mineral composition, and iron ion concentration before and after the measurements were compared, which were used to analyze the influence on the shale’s microscopic pore structure. It features a reduction in the total pore volume after the interaction with the fracturing fluid, with the pore-throat damage degree, porosity damage degree, and permeability damage degree ranging from 0.63% to 5.62%, 1.51% to 6.84%, and 4.17% to 19.61%, respectively. Notably, EM30+ + guar gum mixed water exhibits heightened adsorption retention, alkaline dissolution, and precipitation compared to CNI nano variable-viscosity slickwater, rendering it more deleterious to shale. Moreover, higher concentrations of drag reducers, such as EM30+ or CNI-B, predominantly result in damage to the shale’s micropores. Shale compositions characterized by lower content of quartz and elevated proportions of clay minerals and iron-bearing minerals showcase augmented mineral dissolution and precipitation, consequently intensifying the shale damage. The hydration expansion of mixed-layer illite/smectite profoundly diminishes the core permeability. Consequently, the mechanisms underpinning the damage inflicted on shale’s microscopic pore structure primarily involve fracturing fluid adsorption and retention, mineral dissolution, and precipitation, such as clay minerals and iron-containing minerals.

Micropore Structure of Deep Shales from the Wufeng–Longmaxi Formations, Southern Sichuan Basin, China: Insight into the Vertical Heterogeneity and Controlling Factors

The microscopic pore throat structure of shale reservoir rocks directly affects the reservoir seepage capacity. The occurrence and flow channels of shale gas are mainly micron–nanometer pore throats. Therefore, to clarify the microstructural characteristics and influencing factors of the deep organic-rich shales, a study is conducted on the marine shale from the Upper Silurian to Lower Ordovician Wufeng–Longmaxi Formation in the southern Sichuan Basin. Petrographic lithofacies division is carried out in combination with petro-mineralogical characteristics, and a high-resolution scanning electron microscope, low-temperature nitrogen and low-temperature carbon dioxide adsorption, and micron-computed tomography are used to characterize the mineral composition and pore structure qualitatively and quantitatively, upon which the influencing factors of the microstructure are further analyzed. The results show that with the increase in burial depth, the total organic carbon content and siliceous mineral content decrease in the Wufeng formation to Long-11 subsection deep shale, while clay mineral content increases, which corresponds to the change in sedimentary environment from anoxic to oxidizing environment. Unexpectedly, the total pore volume of deep shale does not decrease with the increase in burial depth but increases first and then decreases. Using total organic carbon (TOC), siliceous mineral content showed a good correlation with total pore volume and specific surface area, with correlation coefficients greater than 0.7, confirming the predominant role of these two factors in controlling the pore structure of deep shales. This is mainly because the Longmaxi shale is already in the late diagenetic stage, and organic matter pores are generated in large quantities. Clay minerals have a negative correlation with the total pore volume of shale, and the correlation coefficient is 0.7591. It could be that clay minerals are much more flexible and are easily deformed to block the pores under compaction. In addition, the longitudinal heterogeneity of the deep shale reservoir structure in southern Sichuan is also controlled by the thermal effect of the Emei mantle plume on hydrocarbon generation of organic matter and the development of natural microfractures promoted by multistage tectonic movement. Overall, the complex microstructure in the deep shales of the Longmaxi Formation in the southern Sichuan Basin is jointly controlled by multiple effects, and the results of this research provide strong support for the benefit development of deep shale gas in southern Sichuan Basin.

Role of magmatism in efficient gas accumulation in Upper Ordovician-Lower Silurian shales in the Yangtze plate, South China: Evidence from the calcite U-Pb ages and gas C-N isotopes

Shale gas exploration in the Yangtze plate has been hindered by strong heterogeneity of gas compositions resulting from magmatism. Borehole core and gas samples from Upper Ordovician-Lower Silurian in the Upper Yangtze plate and the Lower Yangtze plate were analyzed to explore the effects of magmatism on gas accumulation. The analyses included nitrogen isotope of gas, pore structure and X-ray photoelectron spectroscopy of shales, and U-Pb ages of fracture-filling calcites. Our results suggest that magmatism caused the development of micro-fractures in shale reservoirs and accelerated the thermal evolution rate of organic matter. Magmatism in the Upper Yangtze plate predates the peak of gas generation of Upper Ordovician-Lower Silurian shales. Generation and expulsion of hydrocarbon at high temperatures removes 12C from carbon reservoir. After the magmatism, the continuous subsidence of the strata led to further hydrocarbon generation of organic matter. Moreover, the self-sealing property of shale reservoirs were enhanced by the closure of micro-fractures, development of graphite structures, and enrichment of 13C in residual methane, which favor the efficient accumulation of shale gas. Conversely, magmatism in the Lower Yangtze plate occurred after the peak of gas generation of Upper Ordovician-Lower Silurian shales. Magmatism compromised shale gas reservoirs by disrupting sealing conditions, facilitating methane diffusion and atmospheric nitrogen influx. Additionally, overburden pressure led to the collapse of graphitized OM-hosted pores, further inhibiting gas accumulation. Our findings underscore the pivotal role of magmatism in various stages of shale gas accumulation and are critical for exploration strategies in sedimentary basins with prevalent magmatic activities.

Scale-Dependent Fractal Properties and Geological Factors for the Pore Structure in Shale: Insights from Field Emission Scanning Electron Microscopy and Fluid Intrusion

Scale-Dependent Fractal Properties and Geological Factors for the Pore Structure in Shale: Insights from Field Emission Scanning Electron Microscopy and Fluid Intrusion

Pore structure and fractal characteristics of transitional shales with different lithofacies from the eastern margin of the Ordos Basin

AbstractTo better characterize the heterogeneity of transitional shale pore structure and understand its impact on shale gas enrichment, fine characterization of the pore structure of different shale lithofacies was performed by field‐emission scanning electron microscopy, high‐pressure mercury injection, low‐temperature N2 adsorption, and low‐pressure CO2 adsorption. Fractal theory was used to obtain the fractal dimension of the shale pores at different scales and reveal the relationships among the pore structural characteristics, mineral composition, total organic carbon content, and fractal dimension of the shale and their geological significance. The results showed that organic pores, intergranular pores, intragranular pores, and microcracks were generally developed in the transitional shale samples from the study area; elliptic or irregular organic pores were mainly developed in the argillaceous shale lithofacies and siliceous shale lithofacies, and wedge‐shaped or irregular intragranular pores were mainly developed in the calcareous shale lithofacies. The pore size distribution showed a multipeak pattern, and mesopores were the main contributors to the total pore volume (PV), while micropores and macropores contributed little to the total PV. The PV and specific surface area of the siliceous shale were lower than those of the argillaceous shale but higher than those of the calcareous shale, indicating that the change in lithofacies had a significant effect on the shale pores. The common influence of clay minerals, quartz content, and total organic carbon content results in strong heterogeneity and complex pore structure characteristics of shale reservoirs. The pores in the transitional shale from the study area had obvious multiscale fractal characteristics, and the fractal dimension characteristics of different lithofacies and pores at different scales were different, which reflected that the pore structure of the shale had strong heterogeneity. The heterogeneity of the shale pores mainly originated from the macropores and mesopores, while the heterogeneity of micropores was relatively low. The heterogeneity of the pore development and structure at different scales was controlled by the mineral composition matter and organic matter abundance to varying degrees.

Tectonic Control on Shale Pore Structure and Gas Content from the Longmaxi Formation Shale in Southern Sichuan Basin, China: Insights from Fractal Analysis and Low-Pressure Gas Adsorption

Tectonic deformation of different intensities significantly controls shale pore structure, seepage channels, and gas content. The Longmaxi Formation shales in the southern Sichuan Basin have experienced multi-stage tectonic movements, resulting in a diverse fracture system and tectonic deformation. This study focuses on three representative tectonic morphologies: deeply buried strongly deformed (DBSD), deeply buried weakly deformed (DBWD) and shallowly buried weakly deformed (LBWD). We investigated the pore structure characteristics and heterogeneity of these shales under various tectonic conditions using total organic carbon (TOC) content, X-ray diffraction (XRD), scanning electron microscopy (SEM), a low-pressure N2/CO2 adsorption experiment (LP-N2/CO2 GA), and multi-scale fractal theory. The results reveal that strong tectonic compression and deformation conditions lead to the compression and flattening of organic pores by brittle minerals, resulting in long, oriented OM pores. Fracturing of brittle pore creates multiple internal fracture systems linked to dissolution pores, forming a complex micro-fracture–pore network. With intense tectonic deformation, mesopores tend to be compressed, increasing micropore pore volume (PV) and surface area (SA). The DBSD shale exhibits the highest micropore heterogeneity, while the LBWD shale shows the lowest heterogeneity. Fractal analysis indicates a significant decrease in micropore fractal dimension (Df) with increasing burial depth. In contrast, the surface and matrix fractal dimensions (Ds and Dm) of low-buried shale micropores and meso-macropores align vertically. Shale reservoirs in tectonically stable regions exhibit more favourable gas-bearing characteristics than strongly tectonically deformed areas. The LBWD has stable tectonic conditions that are favourable for shale gas preservation. Conversely, slip faults under deep burial conditions lead to extrusion and deformation of shale pore space, ultimately compromising the original reservoir capacity and hindering shale gas enrichment. These findings contribute significantly to our understanding of pore structure and heterogeneity in tectonically deformed shale reservoirs, providing invaluable guidance for the exploration, development, and prediction of shale gas resources.

Pore Structure and Geochemical Characteristics of Alkaline Lacustrine Shale: The Fengcheng Formation of Mahu Sag, Junggar Basin

Shale oil and gas are currently the major fields of unconventional hydrocarbon exploration and development. The Fengcheng Formation (FF) shale in the Mahu Sag of the Junggar Basin is an alkaline lacustrine organic-rich shale with an extremely prospective shale oil potential. However, its strong heterogeneity and complex pore structure greatly influence the development of shale oil. It is significant to investigate the pore and geochemical characteristics of shale reservoirs for shale oil extraction. In this study, the pore structure and geochemical characteristics of FF have been investigated using core analysis, Rock-Eval pyrolysis, X-ray diffraction (XRD), field-emission scanning electron microscopy (FE-SEM), mercury injection capillary pressure (MICP), low-temperature gas adsorption (LTGA), and X-ray computed tomography (X-ray CT). The results show that the shale of FF has moderate organic matter abundance, and the kerogen is mainly of Type II, which is now at the peak of oil generation. Shale minerals are mainly composed of carbonate (dolomite and calcite) and siliceous (quartz and feldspar) minerals, with extremely low clay mineral content. The pore types are mainly intergranular pores (inter-P), intragranular pores (intra-P), and microfractures associated with mineral particles. The pore space is contributed predominantly by micropores of 0.5–1.2 nm and mesopores of 10–50 nm, whereas macropores are underdeveloped. The pores are mostly ink bottle- and slit-shaped, and the pore connectivity is relatively poor. The pore development of shale in the FF is influenced by organic matter abundance, thermal maturity, mineral composition, etc. Organic matter content (TOC), thermal maturity (Ro), and carbonate minerals have a positive effect on pore development, and the pore volume (PV) increases with TOC, Ro, and carbonate minerals. While clay minerals show a negative effect, the PV decreases with clay minerals. Additionally, the influence of the clay mineral content on the pore morphology of shale should not be ignored. This study investigates the pore structure and geochemical characteristics of the alkaline lacustrine shale of FF in Mahu Sag, which is significant to deepen the understanding of alkaline lacustrine shale and to improve the production of shale oil.