Shale Pore Research Articles

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.

Factors Controlling the Pore Development of Low-Mature Marine–Continental Transitional Shale: A Case Study of the Upper Permian Longtan Shale, Western Guizhou, South China

The Upper Permian Longtan Shale is a significant reservoir in western Guizhou. To clarify the main factors controlling the low-mature marine–continental transitional shale pore development in western Guizhou, pore types were classified with scanning electron microscopy (SEM), and the pore developmental stages and morphological structures were quantitatively characterized by nitrogen adsorption isotherm analyses. Additionally, the qualitative or semi-quantitative relationships between the pore developmental stages and the main controlling factors were established via geochemical analysis. The results showed that the Longtan Shale pores include intergranular pores, intragranular pores, organic pores, and microfractures. The intergranular pore structures were categorized into ink-bottle, slit, layered, and irregular types. The intragranular pores were found to be of the elliptical, nearly circular, ink-bottle, and irregular varieties. The organic pores were categorized into elliptical, bubble-like, and irregular polygonal variants. The microfractures were only of the elongated type. The clay-mineral-related intergranular pores were the predominant pore type. The organic pores were found to be poorly developed. The mesopores were predominant, followed by macropores. The shale pore diameters ranged between 1 nm and 100 nm, and they are characterized by multiple peaks. The specific surface area (SSA) was primarily provided by nanopores in the range of 5 nm to 10 nm, such that the smaller pores provided a greater contribution to the SSA, and they are more conducive to shale gas adsorption and accumulation. Clay mineral content was the dominant internal factor controlling pore development and the SSA, with the illite–smectite mixed layer being the most obvious controlling factor. While too low or too high clay mineral content is adverse to macropore development, brittle mineral content, carbonate mineral content, and total organic carbon (TOC) content are adverse to pore development and the SSA. Thermal maturity has no remarkable control effect on pore volume and the SSA of non-organic pores.

Quantitative Characterization of Shale Pores and Microfractures Based on NMR T2 Analysis: A Case Study of the Lower Silurian Longmaxi Formation in Southeast Sichuan Basin, China

In order to quantitatively characterize shale pores and microfractures, twelve marine shale samples from the Longmaxi Formation in the southeastern Sichuan Basin were selected and their NMR T2 spectra were analyzed under the conditions of full brine saturation, cyclic centrifugal treatment and cyclic heat treatment. Then, movable, capillary bound and unrecoverable fluid of shale samples were distinguished and the NMR porosity and full-scale PSD were calculated. Based on NMR spectral peak identification, the relative content of pores and microfractures was determined and their influence factors were analyzed. The results show that the PSD of shale samples is bimodal, with pores distributed in the range of 1 nm to 200 nm and microfractures distributed in the range of 200 nm to 5000 nm, with relative contents in the ranges of 3.44–6.79% and 0.22–1.43%, respectively. Nanoscale organic pores are the dominant type of pores, while inorganic pores and microfractures contribute much less to the shale reservoir space than organic pores. The T2 cutoff values range from 0.55 ms to 6.73 ms, and the surface relaxivities range from 0.0032 µm/ms to 0.0391 µm/ms. Their strong correlation with TOC suggests that organic matter is the main factor controlling the pore type and structure. In addition, the main difference between NMR porosity and He porosity is that gas logging porosity is used to detect connected pores, while NMR porosity also includes closed pores and microfractures. Combined with NMR and high-temperature pressure displacement experimental facilities, this will be a further step towards studying the pore structure of shale under simulated formation conditions.

Molecular dynamics simulations of methane adsorption and displacement from graphenylene shale reservoir nanochannels

Methane is the main component of shale gas and is adsorbed in shale pores. Methane adsorption not only affects the estimation of shale gas reserves but also reduces extraction efficiency. Therefore, investigating the behavior of methane adsorption in shale reservoirs is important for evaluating shale gas resources, as well as understanding its desorption and displacement from the nanochannels of shale gas reservoirs. In this research, molecular dynamics simulations were used to investigate the adsorption behavior of methane gas in organic shale pores made of graphenylene, followed by its displacement by CO2 and N2 injection gases. The effects of pore size, pressure, and temperature on adsorption were examined. It was observed that increasing the pore size at a constant pressure led to a decrease in the density of adsorbed methane molecules near the pore surface, while a stable free phase with constant density formed in the central region of the nanopore. Moreover, adsorption increased with increasing pressure, and at pressures ranging from 0 to 3 MPa, 15 and 20 Å pores exhibited lower methane adsorption compared to other pores. The amount of adsorption decreased with increasing temperature, and the observed adsorption isotherm followed the Langmuir adsorption isotherm. The mechanism of methane displacement by the two injected gases differed. Carbon dioxide filled both vacant adsorption sites and directly replaced the adsorbed methane. On the other hand, nitrogen only adsorbed onto the vacant sites and, by reducing the partial pressure of methane, facilitated the displacement of methane.

Enhancing shale gas recovery by carbon dioxide injection: A method of carbon capture, utilization and storage (CCUS)

CO2 injection in shale gas reservoir can not only increase the production of shale gas, but also realize carbon dioxide capture, utilization and storage. At present, most experimental studies of CO2 injection in shale are carried out by conventional core experiments. However, it is difficult to analyze the process of CO2 replacing shale gas and adsorption in shale pores on microscopic scale. In this study, nuclear magnetic resonance (NMR) technology is used to analyze the migration and conversion of CH4 in process of CO2 injection and depressurization production. Based on above experiments, microscopic mechanism of competitive adsorption of CH4 and CO2 during CO2 injection is clarified, and the stimulation mechanism of CO2 injection to improve shale gas recovery is further proposed. The results show that CH4 preferentially exists in form of adsorption state in shale. When CH4 adsorption amount reaches a certain degree, CH4 gas in form of free state gradually appears. During depressurization stage, further depressurization failed to promote the desorption of adsorbed gas when pressure reduced to 3 MPa. Therefore, adsorbed CH4 gas still exists after depressurization production. Shale has stronger adsorption capacity for CO2 than CH4. CO2 can replace CH4 adsorbed on the pore surface, and promote the desorption of adsorbed CH4 gas to free state. CO2 has the best displacement effect on adsorbed CH4 in pores with diameter of 15.04–21.62 nm, but it fails to replace CH4 in pores with diameter less than 1.08 nm. The competitive adsorption of CO2 and CH4 can effectively promote the further desorption of residual adsorbed CH4 gas after depressurization, and significantly improve the cumulative shale gas production.

Oil content and mobility in a shale reservoir in Songliao Basin, Northeast China: Insights from combined solvent extraction and NMR methods

The volatility of light hydrocarbons means that the conventional dichloromethane (DCM) extraction method may underestimate shale oil content, thereby limiting its usefulness in studies of oil content and mobility within shale pores. Here, a method involving a combination of DCM extraction and low-field (LF)–NMR. spectroscopy was developed for a study of a typical shale oil reservoir in Songliao Basin, Northeast China, measuring its total, adsorbed, mobile, and free oil contents and oil, gas, and water saturation. Factors affecting mobility were also considered. Total oil contents were in the range of 7.2–13.4 mg g−1 rock; adsorbed oil contents determined by DCM extraction accounted for 18%–67% of the total; and total oil saturation was in the range of 23%–40%. Mobile oil saturation ranged from 10% to 32% (17% in average), with free oil saturation averaging 9%. A total-oil correlation coefficient as a function of asphalt A extraction was first time developed. Increasing porosity made no contribution to favorable “sweet spots” for shale oil production. Mobile oil was stored in both meso and macro pores, rather than only in larger pores. Shale intervals with high contents of total organic carbon tended to store oil in an adsorbed state. These findings may improve resource estimation and shale oil sweet spot exploitation.

The formation and evolutionary characteristics of organic matter and pyrites in the continental shales of the 3rd submember of Chang 7 Member, Yanchang formation, Ordos Basin, China

Through microscopic analyses (e.g., organic macerals, thin section observation, scanning electron microscope (SEM) imaging of fresh bedding planes via argon ion milling, and energy spectrum tests) combined with Rock-Eval analyses, this study systematically investigated the organic matter and pyrites in the continental shales in the 3rd submember of the Chang 7 Member (Chang 73 submember) in the Yanchang Formation, Ordos Basin and determined their types and the formation and evolutionary characteristics. The results are as follows. The organic matter of the continental shales in the Chang 73 submember is dominated by amorphous bituminites and migrabitumens, which have come into being since the early diagenetic stage and middle diagenetic stage A, respectively. The formation and transformation of organic matter is a prerequisite for the formation of pyrites. The Ordos Basin was a continental freshwater lacustrine basin and lacked sulphates in waters during the deposition of the Chang 7 Member. Therefore, the syndiagenetic stage did not witness the formation of large quantities of pyrites. Since the basin entered early diagenetic stage A, large quantities of sulfur ions were released as the primary organic matter got converted into bituminites and, accordingly, pyrites started to form. However, this stage featured poorer fluid and spatial conditions compared with the syndepositional stage due to withdraw of water, the partial formation of bituminites, and a certain degree of compaction. As a result, large quantities of pyrrhotite failed to transition into typical spherical framboidal pyrites but grew into euhedral monocrystal aggregates. In addition, pyrites are still visible in the migrabitumens in both microfractures and inorganic pores of mudstones and shales, indicating that the pyrite formation period can extend until the middle diagenetic stage A.

Controlling Effect of Shale Pore Connectivity on the Adsorption State of Shale Gas: A Case Study of Continental Shale of Jurassic Ziliujing Formation, Sichuan Basin

Controlling Effect of Shale Pore Connectivity on the Adsorption State of Shale Gas: A Case Study of Continental Shale of Jurassic Ziliujing Formation, Sichuan Basin

Nanoscale Three-Phase Transport in a Shale Pore Network with Phase Change and Solid–Fluid Interaction

Nanoscale Three-Phase Transport in a Shale Pore Network with Phase Change and Solid–Fluid Interaction

Characteristics and controlling factors of pore structure of shale in the 7th member of Yanchang Formation in Huachi area, Ordos Basin, China

To clarify the influence of organic matter and mineral composition on the pore structure of shale reservoirs in the 7th member of the Yanchang Formation (Chang 7 Member) in the Ordos Basin, we characterized the pore structure of Chang 7 shale reservoirs using argon ion polishing-field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen adsorption (LP-N2A). This characterization was combined with whole-rock mineral composition and organic geochemical experiments to analyze the main controlling factors of the pore structure of Chang 7 Member shale. The results reveal the presence of various pore types in shale, including organic matter pores, intergranular pores, intercrystalline pores, dissolved pores, and micro-cracks. The LP-N2A isotherms of shale consistently exhibit type Ⅱ isotherms with H3 and H4 hysteresis loop characteristics, indicating the relatively developed nature of mesopores and a pore morphology characterized by parallel lamellar and “ink bottle” shapes. The primary determinants of shale pore structure are identified as organic matter, clay minerals, quartz, feldspar, and pyrite. Among these factors, clay mineral phase transformation generates a substantial number of micropores and mesopores within the mineral crystal layers, serving as the main source of shale pores in the study area. Additionally, liquid hydrocarbons generated, solid bitumen, and euhedral pyrite fill inorganic mineral pores, thereby reducing the pore space of Chang 7 shale to a certain extent. These results provide a new cognition into understanding the pore structure characteristics and controlling factors of Chang 7 shale.

Microstructural observations of clay-hosted pores in black shales: implications for porosity preservation and petrophysical variability

AbstractTypical unconventional gas/liquid plays of China were studied using field-emission/focused ion beam scanning electron microscopy (SEM) for clay mineralogy and microstructural development. The SEM microstructural investigations of clay-rich shale and mudstone reservoirs provided significant information about clay mineral type, size, distribution and aggregates, which allows for interpretations regarding porosity preservation and petrophysical variability. The major clay-hosted porosity types are interparticle clay pores, intraparticle clay pores and aggregate pores. Interparticle clay pores occur in open spaces of the clay aggregates and include four subtypes: (1) elongated pores, (2) packed pores, (3) jagged pores and (4) card-house pores. Intraparticle clay pores are present within clay particles and have mostly secondary origin. These pores are diagenesis dependent and are restricted to secondary illite particles during the transformation of clay minerals from smectite to illite. Intraparticle clay pores constitute only isolated porosity and could not contribute to hydrocarbon molecule storage and migration. Aggregate pores were predominantly encountered in association with organic–clay and pyrite–clay aggregates. In places, organic–pyrite–clay aggregates can also display polymerization, but they do not contribute significantly to overall porosity and permeability. Combining SEM morphological analyses with the software ImageJ is critical in clay microstructure and porosity analyses via semi-quantitative characterization of the 3D pore surface, 2D pore profile, pore quantity, pore size, areal porosity, etc. These visual and semi-quantitative results highlight the significance of jagged pores and pyrite–clay aggregate pores in shale gas/liquid reservoirs because they may be important facilitators of gas storage and transmission.

Influence of shale bedding on development of microscale pores and fractures

The characteristics of bedding development have an important impact on the spatial distribution of shale pores and fractures. However, there is a lack of systematic study on the pore and fracture structure of bedding development characteristics. In this paper, the geological control mode of shale type on the development characteristics of pores and fractures is revealed; pore-throat models under different shale lithology conditions are constructed; the control mechanism of bedding development characteristics on the spatial distribution pattern of pores and fractures is clarified. Results show that: (a) The pore space size varies widely from nanoscale to micron-scale or even millimeter scale, and is mainly concentrated in the nanoscale range. (b) For shale samples No. 1-7-1 No. 21-7-1, although the proportion of organic matter and mineral area in different samples varies greatly, the difference between the proportion of organic pore area and the proportion of mineral pore area is not significant, and the proportion of organic pore area is much higher than that of mineral pore area. (c) The pore diameter of shale has strong heterogeneity; minerals have an important impact on throat diameter; maturity has an important impact on throat length; geological compaction and tectonism will have an impact on the tortuosity of shale reservoir pores; the controlling effect of pore connectivity on shale wettability is mainly reflected in the connectivity of hydrophilic and lipophilic pores.

Pore Types and Characteristics of Ultra-Deep Shale of the Lower Paleozoic Wufeng-Longmaxi Formations in the Eastern Sichuan Basin

Recently, shale gas exploration of the Wufeng-Longmaxi formations (WF-LMX) in the Sichuan Basin has gradually stepped into deep to ultra-deep layers, but the pore types and characteristics of ultra-deep shale still remain unclear. In this study, the WF-LMX ultra-deep organic-rich shale samples in the Eastern Sichuan Basin were collected, and the types and development characteristics of shale pores were investigated by using high-resolution scanning electron microscopy (SEM). Our results showed that the pores of the WF-LMX ultra-deep shale reservoirs mainly included organic pores, mineral matrix pores (interparticle pores and intraparticle pores), and micro-fractures, which were dominated by organic pores, displaying oval, slit, and irregular shapes and a diameter of mainly 5–45 nm. Organic pores were poorly developed in primary organic matter (e.g., graptolite and radiolarian), while they were well developed in solid bitumen, being the most important nanopore type in shale. The pore development of ultra-deep shale was mainly controlled by the contents of organic matter and brittle minerals. Higher contents of organic matter and quartz are conducive to the development and preservation of organic pores, which are also favorable for ultra-deep shale gas exploration.

A new multi-scale pore transport capacity model considering elliptical shape and retention effect of unequal-thickness water films

Most of current permeability evaluation models for shale gas reservoirs ignore the influence of imbibition during fracturing, moreover, several of the considerations are different from real conditions, for example, shale pore shape is circular and water film is with equal thickness, which is convenient for calculation but adverse to evaluation accuracy. In the study, shale pore shapes are closer to ellipse by statistically analyzing the scanning electron microscopy results, the thickness of water film is not equal on elliptical pore surface but related to the curvature. Based on these new insights, a quantitative model for determining the unequal thickness of water film was established, and then a new multi-scale elliptical pore permeability model, considering non-equal-thickness water film, wall roughness, stress sensibility, and retention effect, was established based on the multi-scale flow weighting theory. The prediction results of this permeability model are similar to the test results, and are more accurate than that of the previous models. Finally, factors analysis showed that the effect of roughness on permeability was small, but the negative impact of water film and stress sensitivity on permeability was significant.

Complexity and Heterogeneity Evaluation of Pore Structures in the Deep Marine Shale Reservoirs of the Longmaxi Formation, China

The structural evolution and sedimentary differentiation of the Sichuan Basin in China are complex, with intricate reservoir pore structures that significantly impact shale gas production. This study examines the complexity and heterogeneity of the microscopic pore structures in the deep marine shale reservoir in the Longmaxi Formation. Pore structure characterization techniques are used to compare deep and shallow–medium marine shales, and siliceous and silty shales. The results reveal the factors influencing pore structure and their impact on exploration and development. The key points are as follows: (1) The pore structure of deep siliceous shale is the most complex due to its diverse range of pore development patterns, pore types, and sizes. (2) The box dimension of full pore size is about 1.52 for deep marine shale and 1.46 for shallow–medium shale. Organic matter (OM) content, the degree of pore development, and inorganic mineral content all correlate positively with the complexity of the pore structure in deep marine shale, which affects the formation of high-quality reservoirs. (3) Lateral heterogeneity of pore structures shows strong regional variations in the study area. Heterogeneity is more pronounced in the deep marine shale than in the medium and shallow shale formations. OM mesopores significantly influence the overall heterogeneity of the shale pore system. The deep marine shale reservoir is situated in an area with strong regional variations. The pore structure of high-quality reservoirs is more complex than those of shallow–medium marine shales, displaying notable heterogeneity. Pore structures with fractal dimension values close to that of the shallow–medium formations (box dimensions within 1.5) offer promising targets for the exploration and development of deep marine shale gas.

Sedimentary Facies Types and Their Control of Reservoirs in the Lower Jurassic Lacustrine Facies Shale of the Lianggaoshan Formation, Northeastern Sichuan Basin, China

In recent years, new breakthroughs have been made in the field of shale oil and gas exploration in the Lower Jurassic Lianggaoshan Formation in Sichuan Basin. At present, there is a lack of systematic studies on reservoir properties and sedimentary facies of the Lianggaoshan Formation shale. Therefore, in this study, taking the Lianggaoshan Formation in Sichuan Basin as an example, the sedimentary facies types of shale reservoirs and their control over shale oil and gas are systematically studied, based on a large number of outcrops, experimental testing, logging, and seismic interpretation methods. The results show that five sedimentary microfacies are developed in the Lianggaoshan Formation in the study area, namely, semi-deep lake mud, shallow lake mud, wave-influenced shallow lake mud, delta-influenced shallow lake mud, and underwater interbranch bay microfacies. The stratum thickness of the Lianggaoshan Formation is in the range of 26–315 m, and mainly distributed in the eastern region, but rapidly thinned in the northwestern region. The sedimentary sequence framework of the Lianggaoshan Formation has been constructed. Moreover, the lithology of the Lianggaoshan Formation shale has been divided into three types, including shale, massive mudstone and silty mudstone. The brittleness index and total organic carbon (TOC) value of three types of shale show a negative correlation. Silty mudstone has the highest brittleness, while that of black shale is the lowest. For porosity and permeability, massive mudstone is better than silty mudstone, and silty mudstone is better than black shale. There are many kinds of matrix pores in the Lianggaoshan Formation shale, and the development degree of inorganic pores is higher than that of organic pores. Finally, based on the analysis of oil-bearing, pore types, physical properties and productivity, it is considered that black shale facies is the most favorable lithofacies type. The deep–semi-deep lacustrine facies belt obviously controls the shale oil enrichment of the Lianggaoshan Formation.

Lithofacies influence characteristics on typical shale pore structure

Clarifying the three-dimensional pore throat structure characteristics of shale is the foundation for efficient development of shale oil and gas. In this paper, firstly, by using FIB-SEM high-tech characterization technology, three-dimensional quantitative characterization of shale pore-throat structures under different lithological conditions was carried out. Secondly, reconstruct through binary images to establish a three-dimensional pore-throat structure model. Thirdly, the coupling mechanism of “pore distribution, form factor, coordination number, throat diameter” is quantitatively clarified. Results show that: (a). For six shale samples, the volume fraction is mostly concentrated in the range of pore diameter greater than 20 nm and less than 300 nm. When the pore diameter is greater than 300 nm, the proportion of volume fraction is lower. (b). For six shale samples, the pore quantity distribution is mostly concentrated in the range of pore shape factor greater than 0.04 and less than 0.07. When the pore diameter is less than 0.04 or greater than 0.07, the pore quantity distribution is lower. (c). For six shale samples, the pore volume distribution is mostly concentrated in the range of coordination number greater than 1 and less than 4. When the pore diameter is less than 1 or greater than 4, the pore volume distribution is lower. (d). For six shale samples, the throat volume distribution is mostly concentrated in the range of throat diameter greater than 8 nm and less than 120 nm. When the throat diameter is less than 8 nm or greater than 120 nm, the throat volume distribution is lower. The pore structure of shale is very complex, mainly manifested by a variety of pore types.

Origin of carbonate minerals and impacts on reservoir quality of the Wufeng and Longmaxi Shale, Sichuan Basin

The Ordovician-Silurian Wufeng and Longmaxi Shale in the Sichuan Basin were studied to understand the genesis and diagenetic evolution of carbonate minerals and their effects on reservoir quality. The results of geochemical and petrological analyses show that calcite grains have a negative Ce anomaly indicating they formed in the oxidizing environment of seawater. The high carbonate mineral contents in the margin of basin indicate that calcite grains and cores of dolomite grains appear largely to be of detrital origin. The rhombic rims of dolomite grains and dolomite concretions with the δ13C of –15.46‰ and the enrichment of middle rare earth elements were formed during the sulfate-driven anaerobic oxidation of methane. The calcite in radiolarian were related to the microbial sulfate reduction for the abundant anhedral pyrites and δ13C value of –11.34‰. Calcite veins precipitated in the deep burial stage with homogenization temperature of the inclusions ranging from 146.70 °C to 182.90 °C. The pores in shale are mainly organic matter pores with pore size mainly in the range of 1–20 nm in diameter. Carbonate minerals influence the development of pores through offering storage space for organic matter. When calcite contents ranging from 10% to 20%, calcite grains and cement as rigid framework can preserve primary pores. Subsequently, the thermal cracking of liquid petroleum in primary pores will form organic matter pores. The radiolarian were mostly partially filled with calcite, which combining with microcrystalline quartz preserved a high storage capacity.

Characterizing multi-scale shale pore structure based on multi-experimental imaging and machine learning

An accurate and comprehensive understanding of shale pore structure is fundamental and critical for accurate reserves evaluation and efficient hydrocarbon development. Thus, by taking the shale of Paleogene Eocene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin, as an example, the 2D and 3D multi-resolution images of the shale microstructure are obtained by multiple imaging technologies, including X-ray computed tomography, large-field scanning electron microscopy, scanning electron microscopy and focused ion beam scanning electron microscopy. By integrating image processing and machine learning algorithms, the shale pore structure is characterized at a single scale and multi scales. The results are obtained as follows. First, the shale pore space in the study area is mainly composed of microfractures, inorganic pores, organic matters and organic pores, and exclusively shows multi-scale characteristics. Second, there are various types of inorganic pores, and abundant dissolution pores; organic matters are distributed as strips and patches, and no organic pores are found in some organic matters. Third, pores with radius less than 20 nm account for 25%, those with radius between 20 and 50 nm account for 19%, those with radius between 50 and 100 nm account for 29%, those with radius between 100 and 500 nm account for 14%, those with radius between 500 nm and 20 μm account for 11%, and those with radius between 20 and 50 μm account for 2%. Fourth, the organic pores are less connected than the inorganic pores. The connectivity between organic pores and inorganic pores plays a crucial role in hydrocarbon migration, and microfractures control fluid flow channels. Fifth, pores with radius less than 50 nm are dominantly organic pores, those with radius between 50 and 500 nm are mainly organic and inorganic pores, and microfractures mainly contribute to the pores with radius more than 500 nm. It is concluded that a single imaging experiment cannot accurately and comprehensively reveal the multi-scale micro pore structure of a shale reservoir. Through integration of multiple imaging technologies and machine learning algorithms, the shale pore structure can be recognized and characterized at both single scale and multi scales. The proposed new method provides accurate and comprehensive information of multi-scale pore structures.

Impact of Overpressure on the Deep Shale Pore System-A Case Study of Wufeng-Longmaxi Formations from the Southern Sichuan Basin.

This study investigated the effect of overpressure on the deep shale pore system in the Wufeng-Longmaxi Formation (WLF), a well-established shale gas reservoir in the southern Sichuan Basin, China. The Y1 well was drilled to explore deeper overpressured sections of the basin. Organic geochemistry, mineralogy analysis, field emission scanning electron microscopy (FE-SEM), and gas physisorption experiments were conducted to analyze the pore system. Results showed that despite strong compaction, deep organic-rich shale retained large pores. Compared to shallow shale, deep shale had a larger organic porosity with a smaller average pore size, although some pore sizes exceeded those in shallow shale. Nitrogen (N2) adsorption indicated that the abundance of organic matter (OM) affected mesoporous volume and specific surface area (SSA), while carbon dioxide (CO2) adsorption experiments suggested that micropores were not influenced by OM abundance. Comparing calculated pore SSA and volume via gas adsorption of shallower and deep shale samples revealed that, under similar OM abundance, pore SSA was nearly identical, but deep shale had a larger pore volume than shallow shale. The preservation of pores, particularly in deep shale, is attributed to overpressure, which protects against collapse; additionally, generated shale gas during thermal evolution of OM serves as pore support.