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The evaluation of the pore structure in dolomite, particularly with regard to pore heterogeneity, geometry, and connectivity, is crucial for oil and gas field production and reservoir prediction. The subsalt dolomite reservoir in the Ordovician strata of the Ordos Basin has shown promising exploration results and is anticipated to have a high hydrocarbon potential. However, there has been limited research on the pore structure and primary controlling factors of the Ordovician Majiagou reservoir in the south-central Ordos Basin. Therefore, we conducted a comprehensive analysis of the pore structure and fractal characteristics using routine petrophysical measurements, thin-section analysis, and high-pressure mercury injection (HPMI) data. We also discussed the relationship between fractal dimension, reservoir physical properties, and pore structure, along with exploring the origin of potentially prolific reservoirs. Our observations from the thin section identified four main pore types: intercrystalline pores, intercrystalline dissolved pores, dissolved pores, and micro-fractures. The data from HPMI revealed that the average pore-throat radii range from 0.009 μιτι to 0.015 μιτι with porosity ranging from 0.4% to 5.26%, and permeability ranging from 0.011 mD to 0.059 mD. They were further categorized into three reservoir types: dissolved pore type, intra-crystalline (dissolved) pore type, and micro-porous type. The fractal dimension was calculated based on HPMI data, and the reservoir's fractal characteristics were divided into two segments. The dissolved pore type was identified as the potentially prolific reservoir due to its larger pore size and volume, moderate permeability, and homogeneity on pore structure. Additionally, the fractal dimension is negatively correlated with porosity and permeability and positively correlated with sorting coefficient and skewness, suggesting that fractal dimensions are valuable for evaluating reservoir quality and quantitatively characterizing pore networks. [ABSTRACT FROM AUTHOR]

Carbonate reservoirs are characterized by abundant reserves and are currently focal points for development in oil and gas producing regions such as the Ahdab oilfield, Tarim Basin, Sichuan Basin, and Ordos Basin. The primary method for exploiting carbonate reservoirs is waterflooding. However, due to the complex pore structure and pronounced heterogeneity of carbonate rocks, the waterflooding process often leads to an unclear distribution of remaining oil and low waterflooding recovery efficiency, significantly impacting the stable and high production of carbonate reservoirs. This paper presents a two-phase flow model of oil and water in distinct pore structures by integrating fluid flow equations and interface tracking equations. It visually represents the waterflooding process at the pore scale, elucidates the distribution and formation mechanism of remaining oil, and discusses the mechanism of microscopic displacement efficiency change. The study reveals that: 1) After waterflooding, the distribution patterns of remaining oil can be categorized into dead-end remaining oil, pressure balance remaining oil, wall-bound remaining oil, Jamin effect remaining oil, and water-encapsulating remaining oil, which are governed by microscopic pore structure, wettability, and preferential flow paths; 2) From the perspective of actual reservoir displacement efficiency, intergranular pores > intergranular dissolved pores > visceral foramen > mould pore, with this trend being more pronounced under hydrophilic wetting conditions; 3) Given the oil-wet to strong oil-wet wettability characteristics of these carbonate rocks, capillary forces pose significant resistance during waterflooding. The conclusion underscores the importance of leveraging the reservoir's microscopic pore structure and wettability characteristics for actual oil wells, elucidating the evolutionary law of the mechanical mechanism of oil-water interface advancement, clarifying oil-water percolation characteristics at the pore scale, and understanding the microscopic displacement physical mechanism, all of which are crucial for guiding the design of schemes aimed at enhancing reservoir recovery efficiency. [ABSTRACT FROM AUTHOR]

Taking the Longmaxi deep-marine shale gas reservoir in Zigong region as the research target, this paper aimed to characterize the nano-scale pore structure and investigate the reservoirs' heterogeneity based on fractal theory. By conducting a series of experimental studies, mainly including TOC, XRD, gas adsorption (N2 and CH4), we were able to clarify the main controlling factors for the heterogeneity of deep shale pore structure. Our results indicated that the deep marine shale possessed a significant amount of organic matter, as the average TOC value is 3.68%. The XRD analysis results show that quartz and clay were the main mineral types, and the total content of these two minerals averaged 77.5%. Positive correlations were observed between TOC and quartz, while TOC decreases as the clay mineral increases, this discovery indicating that quartz is biogenic. Based on FHH (Frenkele-Halseye-Hill) method, by using the LTNA adsorption isotherms, we took relative pressure P/P0 = 0.5 as the boundary, then two separate fractal dimension were deduced, D1 and D2 represent the fractal characteristics of small and large pores, respectively. Our study revealed that both D1 and D2 demonstrated positive correlations with N2 adsorption pore volume and adsorption specific surface area, while negatively correlated with the adsorption average pore diameter. Moreover, the two fractal dimensions showed positive associations with TOC and quartz and negative associations with clay. Additionally, D1 and D2 also demonstrated a positive correlation with Langmuir volume. The presence of micropores was found to significantly influence the formation of an irregular pore structure in shale. As the pore size decreased, the adsorption specific surface area increased, resulting in a more intricate pore structure, and the fractal dimension of the pores elevated, ultimately. This intricate structure is beneficial for the accumulation of shale gas. These research findings offer valuable insights for the comprehensive assessment of deep shale gas, and enrich our knowledge of enrichment mechanisms in deep shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The discovery of a large number of ancient ivory and ivory artifacts in Sanxingdui site has elevated the importance of ancient ivory relics to the level of exploring the origins of Chinese civilization. To clarify the current preservation status of decayed ivory excavated from the Sanxingdui site, we have conducted an in-depth analysis of the structure-water state relationship of the ivory unearthed from the No. 4 sacrificial pit (K4) as an example. The research indicates that the ancient decayed ivory is composed of a mixed phase of hydroxyapatite [HA, Ca10(PO4)6(OH)2] and carbonated hydroxyapatite [CHA, Ca10(PO4)3(CO3)3(OH)2], which has a mixed structure of sheet-like and needle-like crystals. The organic fibrous protein within the ivory has basically disappeared, resulting in a porous structure with a porosity of approximately 39.2%. The pore size distribution is concentrated in the range of 2.5–100 nm, dominated by mesopores, with a handful of micropores. These pore structures are occupied by adsorbed water, free water and bound water, exhibiting a high water content (35%–40%). These water molecules play a filling and supporting role in the pore structure. During the dehydration and deterioration process of the ancient decayed ivory, the loss of water support results in internal stress within the microstructure of the ivory, leading to irreversible damage such as peeling, pulverization and cracking. The correlation study between the pore structure and water state of ancient decayed ivory provides clues for tracing the geological environment, sacrificial rituals, and ecological environments of ivories in ancient times, serving as a crucial window into Earth’s history and biological evolution.

The marine shale within the Sichuan Basin constitutes China's significant shale gas production, featuring old formation age, high degree of thermal evolution, multiple tectonic movements, and complex structural conditions. However, there are significant differences in the shale gas preservation conditions and reservoir quality in different areas, limiting future large-scale exploration and development. Pore structure significantly influences shale reservoir quality, gas content, and exploration of shale gas occurrence, migration, and enrichment mechanisms. The influence of structural-dominated preservation conditions on shale pore structures is essential to comprehend for effective shale gas exploitation. This study employs field-emission scanning electron microscopy in conjunction with other techniques (low-temperature N2 adsorption, low-temperature CO2 adsorption, and nuclear magnetic resonance) for detailed analyses of the pore structure across varied structural zones, revealing the influence of structural attributes, fault systems, depth of burial, and formation pressure on pore architecture, and examining the relationship between pore structure and shale gas preservation conditions. The results show that stable structural condition is conducive to the development and preservation of shale pores. Structural compression causes inorganic and organic pores to become narrow and elongated due to shrinkage, with a significant increase in microfractures. The porosity of shale with stable structural conditions exhibits markedly increased porosity compared to samples under structural compressions. Under conditions of similar TOC and mineral composition, the pore size distribution (PSD), pore volume (PV), and specific surface area (SSA) of shale after structural compression are significantly lower than those of samples with stable structural conditions. As the burial depth increases, the shale porosity shows a decreasing trend, but the decrease is limited. Burial depth significantly impacts the SSA and PV of high-TOC samples (3%-6%). As the burial depth increases, both SSA and PV show a significant decreasing trend. When the burial depth reaches 4000 m, SSA and PV tend to concentrate. The formation pressure coefficient is an important factor for the development and preservation of shale pores, and porosity is positively correlated with the formation pressure coefficient. Increased formation pressure coefficient indicates superior preservation conditions and enhanced pore development. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

A systematic study of the pore structure characteristics of Lower Cambrian shales in the southeastern Upper Yangtze Platform, was conducted using organic geochemistry, mineralogy, nitrogen adsorption, physical property analysis, and scanning electron microscopy. The results indicate that: 1) The Total organic carbon (TOC) content shows a strong correlation with quartz and clay minerals. Shales with low TOC content and rich in clay minerals primarily exhibit slit-shaped and narrow slit-like inter-clay particle pores with pore size distribution is dominated by mesopores and macropores. Shales with high TOC content predominantly feature narrow slit-like and ink bottle-shaped pores with pore size distribution dominated by micropores and mesopores. 2) Shale pore structures vary significantly under different gas content and preservation conditions. Shales under favorable preservation conditions exhibit a relatively "high porosity, low permeability, and high gas content" pattern, with well-developed organic pores and a strong pore-permeability correlation. In contrast, shales under unfavorable preservation conditions appear dense, with excessively developed fractures increasing both average pore size and local permeability. The pore-permeability correlation is weak, presenting a relatively "low porosity, high permeability, and low gas content" pattern. 3) TOC content plays a crucial role in controlling pore structure, showing overall positive correlations with pore volume, specific surface area, and porosity, and negative correlations with pore size. High TOC content enhances shale plasticity, resulting in lower pore diameters. Factors such as compaction and unfavorable preservation conditions lead to the shrinkage, collapse, and closure of some narrow pore throats, negatively impacting pore volume, specific surface area, brittleness, and fractal dimension, exhibiting a negative correlation with TOC content. 4) The pore structure of Lower Cambrian shales is complex, with fractal dimensions D1 and D2 exhibiting negative correlations with average pore size and positive correlations with TOC, specific surface area, and total pore volume. A high D1 value indicates well-preserved nanoscale pore surface structures with low complexity, suggesting minimal alteration by external fluids and better shale gas preservation. D1 serves as an indicator for shale gas content and preservation conditions. D2 shows better correlations with various pore structure parameters, making it suitable for characterizing pore structures. [ABSTRACT FROM AUTHOR]

The evaluation of the pore structure in dolomite, particularly with regard to pore heterogeneity, geometry, and connectivity, is crucial for oil and gas field production and reservoir prediction. The subsalt dolomite reservoir in the Ordovician strata of the Ordos Basin has shown promising exploration results and is anticipated to have a high hydrocarbon potential. However, there has been limited research on the pore structure and primary controlling factors of the Ordovician Majiagou reservoir in the south-central Ordos Basin. Therefore, we conducted a comprehensive analysis of the pore structure and fractal characteristics using routine petrophysical measurements, thin-section analysis, and high-pressure mercury injection (HPMI) data. We also discussed the relationship between fractal dimension, reservoir physical properties, and pore structure, along with exploring the origin of potentially prolific reservoirs. Our observations from the thin section identified four main pore types: intercrystalline pores, intercrystalline dissolved pores, dissolved pores, and micro-fractures. The data from HPMI revealed that the average pore–throat radii range from 0.009 μm to 0.015 μm with porosity ranging from 0.4% to 5.26%, and permeability ranging from 0.011 mD to 0.059 mD. They were further categorized into three reservoir types: dissolved pore type, intra-crystalline (dissolved) pore type, and micro-porous type. The fractal dimension was calculated based on HPMI data, and the reservoir’s fractal characteristics were divided into two segments. The dissolved pore type was identified as the potentially prolific reservoir due to its larger pore size and volume, moderate permeability, and homogeneity on pore structure. Additionally, the fractal dimension is negatively correlated with porosity and permeability and positively correlated with sorting coefficient and skewness, suggesting that fractal dimensions are valuable for evaluating reservoir quality and quantitatively characterizing pore networks.

Carbonate reservoirs are characterized by abundant reserves and are currently focal points for development in oil and gas producing regions such as the Ahdab oilfield, Tarim Basin, Sichuan Basin, and Ordos Basin. The primary method for exploiting carbonate reservoirs is waterflooding. However, due to the complex pore structure and pronounced heterogeneity of carbonate rocks, the waterflooding process often leads to an unclear distribution of remaining oil and low waterflooding recovery efficiency, significantly impacting the stable and high production of carbonate reservoirs. This paper presents a two-phase flow model of oil and water in distinct pore structures by integrating fluid flow equations and interface tracking equations. It visually represents the waterflooding process at the pore scale, elucidates the distribution and formation mechanism of remaining oil, and discusses the mechanism of microscopic displacement efficiency change. The study reveals that: 1) After waterflooding, the distribution patterns of remaining oil can be categorized into dead-end remaining oil, pressure balance remaining oil, wall-bound remaining oil, Jamin effect remaining oil, and water-encapsulating remaining oil, which are governed by microscopic pore structure, wettability, and preferential flow paths; 2) From the perspective of actual reservoir displacement efficiency, intergranular pores > intergranular dissolved pores > visceral foramen > mould pore, with this trend being more pronounced under hydrophilic wetting conditions; 3) Given the oil-wet to strong oil-wet wettability characteristics of these carbonate rocks, capillary forces pose significant resistance during waterflooding. The conclusion underscores the importance of leveraging the reservoir’s microscopic pore structure and wettability characteristics for actual oil wells, elucidating the evolutionary law of the mechanical mechanism of oil-water interface advancement, clarifying oil-water percolation characteristics at the pore scale, and understanding the microscopic displacement physical mechanism, all of which are crucial for guiding the design of schemes aimed at enhancing reservoir recovery efficiency.

Taking the Longmaxi deep-marine shale gas reservoir in Zigong region as the research target, this paper aimed to characterize the nano-scale pore structure and investigate the reservoirs’ heterogeneity based on fractal theory. By conducting a series of experimental studies, mainly including TOC, XRD, gas adsorption (N2 and CH4), we were able to clarify the main controlling factors for the heterogeneity of deep shale pore structure. Our results indicated that the deep marine shale possessed a significant amount of organic matter, as the average TOC value is 3.68%. The XRD analysis results show that quartz and clay were the main mineral types, and the total content of these two minerals averaged 77.5%. Positive correlations were observed between TOC and quartz, while TOC decreases as the clay mineral increases, this discovery indicating that quartz is biogenic. Based on FHH (Frenkele-Halseye-Hill) method, by using the LTNA adsorption isotherms, we took relative pressure P/P0=0.5 as the boundary, then two separate fractal dimension were deduced, D1 and D2 represent the fractal characteristics of small and large pores, respectively. Our study revealed that both D1 and D2 demonstrated positive correlations with N2 adsorption pore volume and adsorption specific surface area, while negatively correlated with the adsorption average pore diameter. Moreover, the two fractal dimensions showed positive associations with TOC and quartz and negative associations with clay. Additionally, D1 and D2 also demonstrated a positive correlation with Langmuir volume. The presence of micropores was found to significantly influence the formation of an irregular pore structure in shale. As the pore size decreased, the adsorption specific surface area increased, resulting in a more intricate pore structure, and the fractal dimension of the pores elevated, ultimately. This intricate structure is beneficial for the accumulation of shale gas. These research findings offer valuable insights for the comprehensive assessment of deep shale gas, and enrich our knowledge of enrichment mechanisms in deep shale gas reservoirs.

This study investigates pore distribution and permeability behavior of tar-rich coal following high-temperature pyrolysis at 500°C using X-ray computed tomography (CT) scanning. Coal samples post-pyrolysis were CT scanned, generating 1755 cross-sectional slices for three-dimensional reconstruction. An axial algorithm extracted pore distribution features, and geometric parameters were computed. An Equivalent Pore Network Model analyzed permeability characteristics. The results show that Post-pyrolysis pore distribution in tar-rich coal exhibited nonuniformity with a significant range in pore size distribution. Pores displayed concentrated spatial patterns. Total porosity was 14.24%, with 12.34% being connected. Most pores in Representative Elementary Volume (REV) regions fell within 10-50 μιτι in width and 20-60 pm in length, constituting over 40% of the total. Pore surface area peaked between 200-100 pm2, also comprising over 40% of the total. The Pore Network Model showed distinct characteristics in two REV regions: REV-1 demonstrated an early stage of development with poor connectivity, while REV-2 displayed a well-developed network with a bimodal coordination number histogram. The study highlights nonuniform post-pyrolysis pore distribution and significant pore size variations in tar-rich coal. This study is crucial for understanding permeability behavior in tar-rich coal after high-temperature pyrolysis. [ABSTRACT FROM AUTHOR]

The marine shale within the Sichuan Basin constitutes China’s significant shale gas production, featuring old formation age, high degree of thermal evolution, multiple tectonic movements, and complex structural conditions. However, there are significant differences in the shale gas preservation conditions and reservoir quality in different areas, limiting future large-scale exploration and development. Pore structure significantly influences shale reservoir quality, gas content, and exploration of shale gas occurrence, migration, and enrichment mechanisms. The influence of structural-dominated preservation conditions on shale pore structures is essential to comprehend for effective shale gas exploitation. This study employs field-emission scanning electron microscopy in conjunction with other techniques (low-temperature N2 adsorption, low-temperature CO2 adsorption, and nuclear magnetic resonance) for detailed analyses of the pore structure across varied structural zones, revealing the influence of structural attributes, fault systems, depth of burial, and formation pressure on pore architecture, and examining the relationship between pore structure and shale gas preservation conditions. The results show that stable structural condition is conducive to the development and preservation of shale pores. Structural compression causes inorganic and organic pores to become narrow and elongated due to shrinkage, with a significant increase in microfractures. The porosity of shale with stable structural conditions exhibits markedly increased porosity compared to samples under structural compressions. Under conditions of similar TOC and mineral composition, the pore size distribution (PSD), pore volume (PV), and specific surface area (SSA) of shale after structural compression are significantly lower than those of samples with stable structural conditions. As the burial depth increases, the shale porosity shows a decreasing trend, but the decrease is limited. Burial depth significantly impacts the SSA and PV of high-TOC samples (3%–6%). As the burial depth increases, both SSA and PV show a significant decreasing trend. When the burial depth reaches 4000 m, SSA and PV tend to concentrate. The formation pressure coefficient is an important factor for the development and preservation of shale pores, and porosity is positively correlated with the formation pressure coefficient. Increased formation pressure coefficient indicates superior preservation conditions and enhanced pore development.

In cold regions, rocks undergo periodic temperature fluctuations, resulting in deterioration in pore structure and mechanical behavior. This degradation can lead to instability in rock masses and contribute to landslides. While many studies have investigated the effects of freeze-thaw (F-T) cycles on the mechanical behavior of rocks, the micro-level mechanisms of deterioration remain less understood. In this study, the evolution of the pore structure of a prefabricated sandstone with 30 freeze-thaw cycles ranging from −20°C to 20°C is explored using CT scanning. The influence of the prefabricated crack is highlighted. The results indicate a significant impact of freeze-thaw cycles on large pores, with their proportion increasing from 15.28% to 38.72% after 30 F-T cycles. Within the initial 10 F-T cycles, pore structure changes occur without the expansion of prefabricated crack. However, after 15 F-T cycles, prefabricated crack begins extending downward, eventually becoming nearly continuous after 30 F-T cycles. Prefabricated crack notably influences pore distribution during freeze-thaw cycles, with higher porosity near the fracture, where pores initially expand and connect. These findings provide insights into the damage mechanism in sandstone under F-T cycles.

This study investigates pore distribution and permeability behavior of tar-rich coal following high-temperature pyrolysis at 500°C using X-ray computed tomography (CT) scanning. Coal samples post-pyrolysis were CT scanned, generating 1755 cross-sectional slices for three-dimensional reconstruction. An axial algorithm extracted pore distribution features, and geometric parameters were computed. An Equivalent Pore Network Model analyzed permeability characteristics. The results show that Post-pyrolysis pore distribution in tar-rich coal exhibited nonuniformity with a significant range in pore size distribution. Pores displayed concentrated spatial patterns. Total porosity was 14.24%, with 12.34% being connected. Most pores in Representative Elementary Volume (REV) regions fell within 10–50 μm in width and 20–60 μm in length, constituting over 40% of the total. Pore surface area peaked between 200–100 μm2, also comprising over 40% of the total. The Pore Network Model showed distinct characteristics in two REV regions: REV-1 demonstrated an early stage of development with poor connectivity, while REV-2 displayed a well-developed network with a bimodal coordination number histogram. The study highlights nonuniform post-pyrolysis pore distribution and significant pore size variations in tar-rich coal. This study is crucial for understanding permeability behavior in tar-rich coal after high-temperature pyrolysis.

Exploring the geological factors that affect fluid flow has always been a hot topic. For tight reservoirs, the pore structure and characteristics of different lithofacies reveal the storage status of fluids in different reservoir environments. The size, connectivity, and distribution of fillers in different sedimentary environments have always posed a challenge in studying the microscopic heterogeneity. In this paper, six logging curves (gamma-ray, density, acoustic, compensated neutron, shallow resistivity, and deep resistivity) in two marker wells, namely, J1 and J2, of the Permian Lucaogou Formation in the Jimsar Basin are tested by using four reinforcement learning algorithms: LogitBoost, GBM, XGBoost, and KNN. The total percent correct of training well J2 is 96%, 96%, 96%, and 96%, and the total percent correct of validation well J1 is 75%, 68%, 72%, and 75%, respectively. Based on the lithofacies classification obtained by using reinforcement learning algorithm, micropores, mesopores, and macropores are comprehensively described by high-pressure mercury injection and low-pressure nitrogen gas adsorption tests. The multifractal theory servers for the quantitative characterization of the pore distribution heterogeneity regarding different lithofacies samples, and as observed, the higher probability measure area of the generalized fractal spectrum affects the heterogeneity of the local interval of mesopores and macropores of the estuary dam. In the micropore and mesopore, the heterogeneity of the evaporation lake showed a large variation due to the influence of the higher probability measure area, and in the mesopore and macropore, the heterogeneity of the evaporation lake was controlled by the lower probability measure area. According to the correlation analysis, the single-fractal dimension is well related to the multifractal parameters, and the individual fitting degree reaches up to 99%, which can serve for characterizing the pore size distribution uniformity. The combination of boosting machine learning and multifractal can help to better characterize the micro-heterogeneity under different sedimentary environments and different pore size distribution ranges, which is helpful in the exploration and development of oil fields.

Based on porosity and permeability tests, high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR) and centrifugal experiments, this study comprehensively analyzed the quality, pore structure and fractal characteristics of tight sandstone reservoir in meandering stream facies. The purpose is to reveal the relationship between physical properties, geometry and topological parameters of pores, fluid mobility and heterogeneity of pore system of tight sandstone reservoirs in meandering stream facies. The results show that the second member of the Middle Jurassic Shaximiao Formation (J2S2) in the central Sichuan Basin has developed tight sandstone reservoir of meandering fluvial facies, the pore radius of type I reservoir (K>0.3 mD) is mainly distributed at 0.01 μm∼2 μm, the tortuosity ranges between 2.571 and 2.869, and the average movable fluid saturation is 70.12%. The pore radius of type II reservoir (0.08mD

The Jurassic Lianggaoshan Formation lacustrine shale oil is the most potential exploration target of unconventional hydrocarbon resource in Southwest China. In this study, nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), low-temperature N2 adsorption (LTNA), and high pressure mercury intrusion mercury injection capillary pressure are intergrated to reveal pore structure and its controlling factors of Lianggaoshan Formation lacustrine shale reservoir. Results indicate that three types of lithology combination are classified in the Jurassic Liangggaoshan lacustrine shale reservoir. Type A comprises pure shale. Type B is characterized by frequent shell limestone interbedding. Type C is characterized by frequent siltstone interbedding. The Type C shale is characterized by relatively high proportion of organic pores, high development and good connectivity of nanopores, and highest pore volume and Surface area. The nanopores of Lianggaoshan lacustrine shales are mainly dominated by mesopores and part of the macropores. Among them, the PV and SA are both mainly dominated by micropores. The enrichment of organic matter has little effect on the development of micropores, and does not affect the mesopore and macropore development. Quartz particles in Lianggaoshan lacustrine shale do not clearly facilitate the development of micropore and mesopore-macropore. Intraparticle pore in feldspar clast is an important component of mesopore and macropore. Clay minerals has no positive effect on the formation of micropore and mesopore-macropore.

The influence of coalification on coal structure evolution in middle ranked coals is significant for physical assessment of coalbed methane (CBM) reservoirs, which provides insights on the intrinsic connection between coalification jump and pore heterogeneity. A total of 26 middle-ranked coals were samples covering Liupanshui Coalfield in Guizhou Province, Anhe Coalfield in Henan Province, Huaibei Coalfield in Anhui Province, Sanjiang Basin in Heilongjiang Province, Ordos Basin in Shaanxi Province and Qinshui Basin in Shanxi Province. Based on a series of experiments including vitrinite reflectance, coal maceral identification, nitrogen adsorption and the pore fractal method, the inner link between physical property parameters of coal reservoirs and coal rank was revealed. The results show that the coal maceral in middle rank coals is dominated by vitrinite and inertinite and two types of adsorption pores are divided according to the nitrogen adsorption/desorption curves along with pore size distribution. The specific surface area is positively correlated with total pore volume, micropore volume and negatively correlated with averaged pore size and transitional pore volume. The coal samples with low average pore sizes have relatively high total pore volume, specific surface area and micropore volume per unit nm. With the increase of coal rank, the fluctuating points of micropore and transitional pore volume correspond to 1.16%–1.19%, 1.41%–1.43% and 1.86%–1.91% of Ro, max, respectively. The boundary of Ro, max corresponding to the second coalification jump can be more specifically defined as 1.16%–1.19% from the established nominal range of 1.1%–1.3%. The pore fractal dimension DNA1 and DNA2 increase with increasing specific surface area. Furthermore, the DNA2 has a negative correlation with micropore volume and averaged pore size, indicating that the coal with smaller average pore diameter and lower micropore content has a more complex pore structure.

Abundant pore space in coal is not only the place for the accumulation of coalbed methane (CBM), but also the tunnel for gas migration. In this study, five sets of coal samples before and after the second coalification were selected from the eastern margin of Ordos Basin to simulate supercritical CO2 (Sc-CO2) extraction in supercritical extraction equipment. The evolutions of pore structure and porosity were tested by mercury intrusion porosimetry and nuclear magnetic resonance spectroscopy to compare the changes of pore structure and porosity due to the Sc-CO2 extraction, and to explain the related mechanism. The results show that: (1) Pore volume, pore specific surface area, and connectivity characteristics changed significantly due to Sc-CO2 extraction, and the increment of pore volume and pore specific surface area presented a law of increase–decrease–increase with the increase in the coal rank, and the turning point was near the second coalification. (2) The porosity increment change trend due to Sc-CO2 extraction was increase–decrease–increase with increasing coal rank, and the turning point was again near the second coalification, which supports the mercury intrusion porosimetry results. (3) The changes were observed in the porosity characteristics due to Sc-CO2 extraction through pore-increasing and expanding effects. Before the second coalification, the pore-increasing and expanding effects co-existed in the micropores, and after the second coalification, the pore-expanding effect mainly existed in the transitional pores and above. (4) The variation model for the pore structure of coal due to Sc-CO2 extraction was established. The conclusions offer not only important theoretical significance for the CO2-enhanced CBM (CO2-ECBM) mechanism but also important significance for CO2-ECBM engineering.

Injecting CO2 into shale reservoirs has dual benefits for enhancing gas recovery and CO2 geological sequestration, which is of great significance to ensuring energy security and achieving the “Carbon Neutrality” for China. The CO2 adsorption behavior in shales largely determined the geological sequestration potential but remained uncharted. In this study, the combination of isothermal adsorption measurement and basic petro-physical characterization methods were performed to investigate CO2 adsorption mechanism in shales. Results show that the CO2 sorption capacity increase gradually with injection pressure before reaching an asymptotic maximum magnitude, which can be described equally well by the Langmuir model. TOC content is the most significant control factor on CO2 sorption capacity, and the other secondary factors include vitrinite reflectance, clay content, and brittle mineral content. The pore structure parameter of BET-specific surface area is a more direct factor affecting CO2 adsorption of shale than BJH pore volume. Langmuir CO2 adsorption capacity positive correlated with the surface fractal dimension (D1), but a significant correlation is not found with pore structure fractal dimension (D2). By introducing the Carbon Sequestration Leaders Forum and Department of Energy methods, the research results presented in this study can be extended to the future application for CO2 geological storage potential evaluation in shales.

Evaluation of tight oil reservoir properties is of great significance to the exploration of oil and gas in tight reservoirs. The Chang 1 Member of the Yanchang Formation in the Wanhua Area, Ordos Basin is a new exploration stratum for tight sandstone oil. The lack of understanding of reservoir characteristics and crude oil enrichment rules has seriously restricted the efficient development of oil and gas resources in this stratum. In this study, the reservoir characteristics of the Chang 1 Member in the Wanhua area and the effects of superimposed sand bodies, structures and paleogeomorphology on accumulation of hydrocarbons were systematically studied. The Chang 1 sandstone is a typical ultra-low porosity-ultra-low permeability reservoir, and it has experienced destructive diagenesis of mechanical compaction, pressure solution and cementation, and constructive diagenesis of dissolution. Strong pressure solution caused the secondary enlargement of quartz and feldspar and the formation of patchy dense mosaic structures. The target layer has experienced argillaceous, siliceous and carbonate cementations. Moreover, the sandstone reservoir in the Chang 1 Member also experienced strong dissolution, and it is the main factor for the formation of secondary pores and the improvement of reservoir physical properties. The study also found that the main types of pores in the Chang 1 Member are intergranular dissolved pores and remaining intergranular pores. Superimposed sand bodies, nose-shaped uplifts, dominant facies and eroded paleo-highlands have significant effects on the hydrocarbon accumulation. Based on this study, it was found that the migration and accumulation mode of hydrocarbons in the Chang 1 reservoir belongs to the ladder-like climbing migration + structural ridge accumulation type. In addition, sand body thickness is an important controlling factor for the hydrocarbon accumulation. At present, the discovered crude oil in the Chang 1 Member is always distributed in the areas with thick sand bodies (>20 m), and most of the sand bodies have a thickness in the range of 25–40 m, and the effective thickness is in the range of 2–6 m. In addition, the eroded highlands are the highest topographic units, they are favorable areas for the large-scale accumulation of oil and gas.

In order to establish a quantitative evaluation system for reservoir quality suitable for tight oil sandstones, in this study, taking the Chang 7 Member in the Maling area of the Ordos Basin as an example, the nuclear magnetic resonance, clay mineral analysis, high pressure mercury injection analysis and logging interpretation technology have been used to carry out a comprehensive evaluation of the pore structures, sand body structures and oil-bearing properties of tight oil sandstone reservoirs. The results show that the pseudo-capillary pressure curves transformed by the NMR T2 spectra are consistent with the capillary pressure curves measured by the core experiments. This method can be used for accurate characterization of the pore structures of the reservoir. The pore structure parameters calculated based on the pseudo-capillary pressure curves can accurately reflect the pore structures of the reservoirs such as micropores-thin throats and complex tortuosity. At the same time, the smoothness feature of conventional logging curves is used to evaluate the sand body structures and heterogeneity of the reservoir, and the apparent energy storage coefficient is introduced to quantitatively evaluate the oil-bearing properties of tight oil reservoirs. The evaluation results are in good agreement with the actual production situation. The larger the apparent energy storage coefficient, the higher the initial output of the oil wells. The evaluation results of the reservoir quality of the tight oil sandstones constructed in this paper are highly consistent with the production status, so the method has broad application prospects.

The Lower Permian Shanxi Formation in the Eastern Ordos Basin is a set of transitional shale, and it is also a key target for shale gas exploration in China. Three sets of organic-rich transitional shale intervals (Lower shale, Middle shale and Upper shale) developed in Shan 23 Submember of Shanxi Formation. Based on TOC test, X-diffraction, porosity, in-situ gas content experiment and NMR experiments with gradient centrifugation and drying temperature, the reservoir characteristics and pore fluid distribution of the three sets of organic-rich transitional shale are studied. The results show that: 1) The Middle and Lower shales have higher TOC content, brittleness index and gas content, reflecting better reservoir quality, while the Upper shales have lower gas content and fracturing ability. The total gas content of shale in the Middle and Lower shales is high, and the lost gas and desorbed gas account for 80% of the total gas content. 2) The Middle shale has the highest movable water content (32.58%), while the Lower shale has the highest capillary bound water content (57.52%). In general, the capillary bound water content of marine-continental transitional shale in the Shan 23 Submember of the study area is high, ranging from 39.96% to 57.52%. 3) Based on pore fluid flow capacity, shale pores are divided into movable pores, bound pores and immovable pores. The Middle shale and the Lower shale have high movable pores, with the porosity ratio up to 27%, and the lower limit of exploitable pore size is 10 nm. The movable pore content of upper shale is 25%, and the lower limit of pore size is 12.6 nm. It is suggested that the Lower and Middle shales have more development potential under the associated development technology.

The primary focus of oil and gas exploration for tight sandstone reservoirs is on a quantitative characterization of reservoir properties. This paper uses the tight sandstone reservoir developed in the Gaotaizi oil layer in the Qijia area of the Songliao Basin as an example. The petrology, physical properties, pore–throat characteristics, and the genesis of the densification of the oil-bearing sandstones are elucidated using casting thin-sections, scanning electron microscopy, 3D computerized tomography (CT), and petrophysical experimental techniques. The results show that the Gaotaizi oil layer is mainly composed of clastic rocks and contains small amounts of shell limestone. The clastic rocks are mainly lithic feldspar sandstone and feldspar lithic sandstone, while residual intergranular pores, intergranular dissolved pores, intragranular dissolved pores, intragranular pores and intercrystalline pores constitute the different pore types. Mercury intrusion and 3D computerized tomography analysis showed that micro-nano pores account for 53% of the total pores present. The pore–throat coordination number is distributed between 1 and 4, with an average of 1.8. The pores and throats in the Gaotaizi reservoir have poor connectivity. The porosity distribution of the Gaotaizi oil layer is 1.4%–22.5%, with an average of 9.5%, while the permeability distribution ranges from 0.01 to 27.10 mD, with an average of 0.41 mD. It is an ultra-low porosity and ultra-low permeability tight reservoir. The Gaotaizi oil layer is divided into three types of reservoirs through a systematic study of its pore developmental characteristics. Diagenetic processes like compaction and cementation result in a reduction in porosity and permeability. Compaction, calcite and siliceous cementation, and illite packing are primarily responsible for reservoir densification.

In order to quantitatively characterize the pore structure of thermally contacted metamorphic coal by igneous intrusion and investigate the intrinsic connection between the pore and dispersion properties of coal, the samples of metamorphic coal from different locations of Daxing Coal Mine were collected and processed. The correlative analysis on pore characteristics, including pore area, perimeter, shape factor and fractal dimension of pores with different sizes, were carried out by using scanning electron microscopy (SEM) and pore-fracture analysis system (PCAS). The results show that the porosity of macro- and meso-pores and the number of pores in the metamorphic coal are larger than those of the normal coal. The total length of pores per unit area and the average shape factor increase, and the connectivity of pore is raised, resulting in an enhanced gas release capacity (increased V1) within the first one second. The proportion of gas emission in the first one second of metamorphic coal is much higher than that of other coals. The decrease of pore volume and specific surface area of micropores makes the adsorption capacity weaker, which results in a decrease in the total amount of emission - smaller Δp value, and earlier inflection point and faster attenuation on the emission curve, namely an increased α value. In addition, the V1, α value and volatile content satisfy the quadratic nonlinear and linear relationships, respectively. In the prediction of outburst risk of thermally contacted metamorphic coal, it is more reasonable to use the V1 index to characterize the gas release rate.

In this study, the microscopic pore characteristics of shale in marine strata are evaluated. Based on field emission scanning electron microscopy (FE-SEM), low-temperature N2 adsorption (LT-N2GA), low-pressure CO2 adsorption (LP-CO2GA) and high-pressure methane adsorption (HPMA) experiments, the pore characteristics of 12 shales from the Wufeng–Longmaxi Formations in northern Yunnan and Guizhou are characterized qualitatively and quantitatively. Fractal Frenkel–Halsey–Hill (FHH) theory is used to analyse the fractal characteristics, and the adsorption pore characteristics of shale are discussed. The correlation between the fractal dimension and pore structure and adsorption performance is determined. The results show that the total organic carbon (TOC) contents of the 12 shales are in the middle–low level, ranging from 0.43% to 5.42%, and the shales are generally in the highly mature to overmaturity stage (vitrinite reflectance (Ro) values between 1.80% and 2.51%). The mineral composition is mainly quartz and clay minerals. The average clay mineral content is 40.98% (ranging from 24.7% to 63.3%), and the average quartz content is 29.03% (ranging from 16.8% to 39.6%), which are consistent with those of marine shale in the Sichuan Basin. FE-SEM and LT-N2GA isotherms reveal a complex shale pore structure and open pore style, mainly ink bottle-shaped and parallel plate-like pores. The total pore volumes (PVs) range from 0.012–0.052 cm3/g, and the specific surface area (SSA) values range from 18.112–38.466 m2/g. All shale samples have abundant micropores and mesopores, accounting for >90% of the total SSA. The fractal dimensions, D1 and D2, were obtained from N2 adsorption data, with different adsorption characteristics at 0–0.5 and 0.5–1.0 relative pressures. The fractal dimensions increase with increasing BJH PV and BET SSA and decrease with decreasing average pore diameter (APD). The fractal dimensions are positively correlated with the TOC and clay mineral contents and negatively correlated with the quartz content. The fractal dimension can be used to evaluate the methane adsorption capacity; the larger the fractal dimension is, the larger the methane adsorption capacity is. Fractal analysis is helpful to better understand the pore structure and adsorption capacity of shale gas reservoirs.

Shahejie marl in the Shulu Sag is a crucial resource for unconventional hydrocarbon exploration in China. Although breakthroughs have been made in tight oil exploration in this area, the mechanisms underlying the formation of this marl reservoir and factors controlling its ‘sweet spots’ have not been thoroughly studied. To understand the pore structure characteristics and factors influencing the marl reservoir, we analyzed core samples from Wells ST1 and ST3. A series of experiments was conducted on the samples, such as X-ray diffraction, focused ion beam scanning electron microscopy, micro-CT, and total organic carbon test. Additionally, the physical properties of different marl rock fabrics were studied with auxiliary tests, such as mercury intrusion capillary pressure analyses, nuclear magnetic resonance, porosity and permeability tests, and thin-section observation. The results revealed that the marl reservoir is characterized by low porosity (1.61%) and low permeability (2.56mD). The porosity and permeability (1.61% and 3.26mD) of laminated marl were better than those (0.92% and 1.68mD) of massive marl. Clay minerals and quartz content in laminated (11.8 and 8.2%) was less than in massive marl (16.2 and 13.3%). The marl pores include intercrystalline pores, dissolution pores, and microfractures. Additionally, the laminated marl pores were primarily distributed along the dark lamina, with good connectivity. A few isolated and uniform holes were observed in the massive marl. Influenced by rock fabric and mineral composition, layered fractures were mainly developed in the laminated marl, while structural fractures were the main type of microfractures in the massive marl. The primary sedimentary mechanism was the main geological action underlying the differences in marl rock fabric; this mechanism affects the physical properties of the marl reservoir, which are key factors to be considered when searching for the marl reservoir ‘sweet spots’. Particular attention should be paid to these factors during tight oil exploration and development in similar sedimentary basins.

Pore structure study is an important part of unconventional shale reservoir characterization, since the pore system provides the primary petroleum storage space and fluid flow pathways. Previous studies have suggested that the pore structure is related to the total organic carbon (TOC) content, mineral compositions, and the maturity of the organic matter (OM). However, few studies have focused on the mineral grains, the primary grains being deposited but before cementation, which are the building blocks of shale. Eight Woodford Shale outcrop samples from southern Oklahoma were chosen to study the effects of mineral grain size on the pore structure characterization, using multiple and complementary experimental approaches, including laser diffraction, mineralogy, TOC, pyrolysis, liquid immersion porosimetry, mercury intrusion porosimetry, gas physisorption, (ultra) small angle X-ray scattering, scanning electron microscopy, and spontaneous imbibition. The results from different experiments of eight samples show that the Woodford Shale has the mean mineral grain diameters at 3–6 μm, a wide range of porosity at 3–40% and pore diameters at 50–1,000 nm, and various pore connectivity. Grain size variation was probably caused by the sea-level fluctuation during its deposition, which affect the porosity, pore size distribution, and pore connectivity. With decreasing mineral grain sizes, the porosity tends to increase while the pore connectivity worsens. The results also indicate that OM and carbonates in this low-maturity Woodford Shale could block the pores and decrease the porosity. Coupling with the grain size analyses, the control of depositional environment on grain sizes and subsequent effects on pore structure is identified. The pore structure characteristics over a wide pore-diameter range provided by multiple experiments could improve the understanding of storage space and fluid flow in the Woodford Shale to further increase its petroleum production.

To characterize the coal measure shale pore structure of the Xiashihezi Formation in the Sunan Syncline block, a series of experiments were conducted. Results show that the main components of the shales are clay minerals and quartz, and organic matter, fluid escaping, interlayer, intercrystalline and interparticle pores are well-developed. The shale pore specific surface area (SSA) is concentrated in the pores with the size of

The enrichment law of tight sandstone gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin has not been fully revealed. In this study, the controlling effect of source-reservoir assemblage on gas accumulation in the Xujiahe Formation was systematically investigated. The results show that pores and fractures are developed in the tight sandstone reservoirs of the Xujiahe Formation. The main pore types are intragranular dissolved and intergranular pores. The quality of sandstone reservoirs in the Xujiahe Formation is controlled by sedimentation, diagenesis and tectonic processes. Underwater distributary river channels and estuary bars are favorable microfacies for reservoir development, and chlorite cemented facies and dissolution-kaolinite cemented facies are the most favorable diagenetic facies. In addition, the natural gas composition and carbon isotope characteristics of the Xujiahe Formation are significantly different in different intervals of the same gas field and the same interval of adjacent gas fields. This shows that the natural gas has no obvious vertical mixing and lateral migration, and it has the distribution characteristics of “local enrichment”. Then, the natural gas will be preferentially charged in the feldspar lithic sandstone and feldspar quartz sandstone with large thickness and good physical properties by means of short-range migration. According to the research, the hydrocarbon supply capacity of the single layer in each interval is weak, and it leads to the low filling degree of the gas reservoir and the insufficient separation of gas and water. On the whole, four sets of extra-source “lower generation and upper storage” assemblages and two sets of “self-generation and self-storage” source-reservoir assemblages are developed in the Xujiahe Formation. The development scale of natural gas is mainly controlled by the type of source-reservoir combination, and the areas with close source-reservoir contact and high hydrocarbon generation intensity are high-quality reservoir development areas.

In recent years, the eastern margin of Ordos Basin has attracted much attention as a key base for unconventional natural gas exploration. The pore-fracture structure is an important physical property of shale and provides places and channels for methane storage and migration. In this study, an integrated method of X-ray diffraction, total organic carbon (TOC), vitrinite reflectance (Ro), scanning electron microscopy (SEM), and low-temperature N2 adsorption was performed to reveal the microstructure and heterogeneity of coal-bearing organic shale in the southeast Ordos Basin. The result indicated that the studied shale belongs to the category of organic-rich shale with an average TOC content of 8.1% and reaches the dry gas stage with a mean Ro value of 2.41%. Hysteresis loop suggests the shapes of pore structure in shale samples are dominated by inkbottle, cylindrical pores or parallel-plate. A positive correlation between kaolinite and pore surface area indicates that kaolinite contributes greatly to micropores with a large specific surface area. Intense hydrocarbon generation promotes gas to escape from organic components’ surfaces, thereby increasing the pore volume. Coal-bearing shales with high brittleness may contain more natural microfractures, increasing specific surface area and pore volume. The bocking effect of minerals in microfractures may reduce pore connectivity and connectivity and enhance shale heterogeneity. The pore volume and specific surface area of coal-bearing shale are closely related to the fractal dimensions. The high complexity of the shale microstructure may lead to the formation of more micropores, resulting in a decrease in the average pore size. Besides, organic and clay-hosted pores in coal-bearing shale with high maturity may well be the main storage space for methane, but the methane is mainly stored in organic pores in marine shale.

Research on the microscopic migration characteristics of fluids in coal measure sandstone has always been a hot spot in the evaluation of reservoir properties. In this study, taking the Yan’an Formation sandstone reservoirs in the Block A of the Ordos Basin as an example, the pore structures and fluid migration characteristics of coal-measure sandstones are systematically studied using a large number of thin sections, SEM (Scanning Electron Microscope), NMR (Nuclear Magnetic Resonance), relative permeability and water-flooding test results. The results show that the Jurassic sandstones in the target layer mainly develop lithic quartz sandstone, and the main pore types are intergranular and dissolution pores, followed by a small amount of intercrystalline pores. The surface porosity of the target sandstones mainly ranges from 7.90 to 10.79%, with an average value of 8.78%. The good correlation between porosity and permeability indicates that the target layer is a pore-type reservoir. The T2 relaxation time of the target layer is mainly distributed within 100 ms. Moreover, the reservoir of the Yan’an Formation has a high saturation of movable fluids, which is mainly distributed in 43.17–71.24%, with an average value of 56.90%. Meanwhile, samples with fractures have higher movable fluid saturations. In addition, the average irreducible water saturation of the Yan’an Formation sandstone reservoir is 35.14%, and the final oil displacement efficiency is 51.14% on average. There is a good positive correlation between the oil displacement efficiency and the co-permeability zone. As the co-permeability zone range increased from 15 to 55%, the oil displacement efficiency increased from 30 to 65%. When the cores develop fractures, they have characteristics of high permeability, high oil recovery rate, high oil displacement efficiency in the anhydrous period, low irreducible water saturation and low residual oil saturation.

The pore structure is an important factor affecting reservoir capacity and shale gas production. The shale reservoir of the Longmaxi Formation in the Changning area, Southern Sichuan Basin, is highly heterogeneous and has a complex pore structure. To quantitatively characterize the shale’s pore structure and influencing factors, based on whole rock X-ray diffraction, argon ion polishing electron microscopy observations, and low-temperature nitrogen adsorption-desorption experiments, the characteristics of the shale pore structure are studied by using the Frenkel-Halsey-Hill (FHH) model. The research reveals the following: 1) The pores of the Longmaxi Formation shale mainly include organic pores, intergranular pores, dissolution pores and microfractures. The pore size is mainly micro-mesoporous. Both ink bottle-type pores and semiclosed slit-type pores with good openness exist, but mainly ink bottle-type pores are observed. 2) The pore structure of the Longmaxi Formation shale has self-similarity, conforms to the fractal law, and shows double fractal characteristics. Taking the relative pressure of 0.45 (P/P0 = 0.45) as the boundary, the surface fractal dimension Dsf and the structural fractal dimension Dst are defined. Dsf is between 2.3215 and 2.6117, and the structural fractal dimension Dst is between 2.8424 and 2.9016. The pore structure of micropores and mesopores is more complex. 3) The mineral components and organic matter have obvious control over the fractal dimension of shale, and samples from different wells show certain differences. The fractal dimension has a good positive correlation with the quartz content but an obvious negative correlation with clay minerals. The higher the total organic carbon content is, the higher the degree of thermal evolution, the more complex the pore structure of shale, and the larger the fractal dimension. The results have guiding significance for the characterization of pore structure of tight rocks.

The intensive study of the pore structure and its controlling factors of shale reservoir has important guiding significance for further exploration and exploitation of shale gas. This work investigated the effects of organic and inorganic compositions on the development of pore structures of the Upper Permian Shanxi shale in the southern Yan’an area, Ordos Basin. Based on the results of high-pressure mercury intrusion, low-pressure N2 and CO2 adsorption and organic geochemical experiments, X-ray diffraction and scanning electron microscope observations, the mineral composition, pore structure and its influencing factors of the transitional shale were studied systematically. The results indicate that the total organic carbon (TOC) content of the shale is between 0.12% and 5.43%, with an average of 1.40%. The type of the organic matter (OM) belongs to Type III and has over maturity degree with an average Ro of 2.54%. An important character of this kind of shale is the large proportion of clay mineral content, which ranges from 40.70% to 87.00%, and with an average of 60.05%. Among them, illite and kaolinite are the main components, and they account for 36.6% and 36.7% of the total clay minerals respectively, followed by chlorite and illite/smectite (I/S) mixed layer. The quartz content is between 10.6% and 54.5%, with an average of 35.49%. OM (organic matter) pores are mostly circular bubble-shaped pores, and most of them are micropores, while inorganic pores are well developed and mainly contributed by clay mineral pores and have slit-type, plate-like and irregular polygon forms. Mesopores are the major contributor to pore volume (PV), while micropores contribute the least to PV. The contribution of micropores to the specific surface area (SSA) is greater than 61%, followed by mesopores. Macropores have almost no contribution to the development of SSA. OM pores are the main contributor to the total specific surface area of the shale, with an average contribution rate of 61.05%, but clay mineral pores contribute more to the total pore volumes. In addition, both the content of chlorite and illite/smectite (I/S) mixed layer is positively correlated with the volume ratio of mesopores. It was found that high TOC, I/S mixed layer and chlorite content are all favorable conditions for the target shale.

Lower Permian Fengcheng Formation is considered to be a high-quality alkaline lacustrine shale oil resource in the Junggar Basin, NW China. Based on core and thin section observation, X-ray diffraction, scanning electron microscope, low-pressure N2 adsorption, and high-pressure mercury intrusion porosimetry, different shale lithofacies, and pore structures were examined. According to the mineral composition, shales in well My 1 are divided into five types: dolomitic mudstone, calcareous mudstone, siliceous mudstone, tuffaceous mudstone, and argillaceous mudstone, each of which shows its pore structure distribution. Intragranular pores, inter-crystalline pores associated with clays and pyrites, dissolution pores, and microfractures were commonly observed. There are three segments of pore structures including 4 μm. Clay minerals mainly contribute to mesopores, especially in argillaceous mudstones. The dissolution of carbonate minerals and feldspars is significant for macropores predominantly in dolomitic mudstones and tuffaceous mudstones, respectively. Micron-scale microfractures associated with laminae dominate in dolomitic mudstones. Therefore, the dolomitic mudstones, especially with lamination, and tuffaceous mudstones are proposed to be favored shale lithofacies with great exploration potential in the Mahu Sag.

At present, the Carboniferous-Permian shale gas in the South North China Basin is still in the exploration stage, and the understanding of the microscopic pore structures, mineral composition and hydrocarbon enrichment law of the marine-continental transitional shale gas reservoirs in this area is extremely limited. In this paper, taking the Carboniferous-Permian shale gas reservoir in the South North China Basin as an example, the geological conditions of shale gas accumulation have been systematically studied using a large amount of sedimentary, logging, seismic, core, geochemical, physical property, and scanning electron microscope data. The study shows that the transitional dark shale is stable and widely distributed in the South North China Basin. Among them, the average thickness of the high-quality shale in the Taiyuan Formation is 67 m, while that of the Shanxi Formation is 56 m. Carboniferous and Permian are the main strata for the distribution of shale gas resources. Among them, the dark shale developed in the Taiyuan and Shanxi Formations has the largest thickness and the highest organic matter abundance. In addition, the organic matter types of the Upper Paleozoic coal-measure source rocks in the South North China are mainly II2-III types, and a small part of them belong to II1 types. The brittle minerals in the target shale are mainly quartz, and the content of illite is the highest among the clay minerals. Porosity is negatively correlated with clay mineral content, and positively correlated with quartz and TOC content. In addition, the permeability is negatively correlated with the organic matter content. Finally, the criteria for key indicators of the transitional shale gas reservoirs in the South North China Basin were developed.

Studying complex pore structures and fractal characteristics of gas shale provides significant guidance for clarifying the mechanism of shale gas accumulation and realizing its efficient development. In this paper, 12 samples of Taiyuan Formation shale are used as the research object, and the fractal theory is combined with mercury intrusion porosimetry and N2 adsorption technology to innovatively solve the problem of splicing point selection, which can reveal the full-scale pore size distribution of shale. The results demonstrate that the most common types of pores in the chosen samples are pores between or within clay minerals, micropores and mesopores inside organic matter, and microfractures, based on scanning electron microscopy imagery analyses. The pores of shale samples have fractal geometries. The fractal dimension DM1 values in the mercury intrusion porosimetry experiments range from 2.3060 to 2.6528. Two fractal dimensions, DN1 and DN2, may be obtained using the Frenkel-Halsey-Hill fractal method. DN1 values vary from 2.4780 to 2.6387, whereas DN2 values range from 2.5239 to 2.7388. Most macropores in shale samples have a size range of about 0.2 mm, with a wide pore size distribution, and the largest peak of the micro-mesopore volume is generally about 50 nm. The fractal dimension correlates positively with the corresponding pore volume, although the correlation between volume and composition is weak. The relatively strong correlation between fractals and the basic compositions of shale proves the fractal theory’s relevance in defining pore inhomogeneity. This study would contribute to the development of a fractal perspective-based method for pore splicing while also expanding our understanding of pore morphology and structure in transitional shale.

Investigation of pore structure is vital for shale reservoir evaluation and also “sweet spot” prediction. As the strong heterogeneity in pore types, morphology, and size distributions of organic matter-rich shales, it is essential to combine different approaches to comprehensively characterize them.Field emission-scanning electron microscopy (FE-SEM), low-pressure gas (CO2 and N2) adsorption, and high-pressure mercury intrusion (HPMI) were employed to systematically investigate the pore structure of the lower Longmaxi shale reservoirs in the northern Guizhou area. The results show that the shales can be divided into four lithofacies based on mineral composition, namely, siliceous shale (SS), clay shale (CS), carbonate shale (CAS), and mixed shale (MS), among which siliceous shale is the primary lithofacies of the Longmaxi shale. Numerous organic matter (OM)-hosted pores, clay interlayer pores, interparticle pores, and intraparticle pores were identified within shale reservoirs. The specific surface area ranges from 11.3 to 27.4 m2/g, with an average of 18.1 m2/g. It exhibits a strong positive correlation with TOC contents, suggesting that organic matter is the major contributor to the specific surface areas. A wide range of pore size distribution was measured by integration of gas adsorption and HPMI. It is shown that the pore size is primarily distributed within ∼100 nm, corresponding to micropores, mesopores, and part of macropores. The total pore volume, which is mostly derived from the contribution of micropores and mesopores, remains within a range of 0.11 to 0.025 ml/g, with an average of 0.018 ml/g. Furthermore, the volume of micropores and mesopores is mainly controlled by organic matter contents. The dissolution pore contributes most to the macropore space within shale reservoirs, based on the positive correlation with macropore volume and easily dissolved minerals, including carbonate and feldspar. Also, the total pores volume is mainly dominated by organic matter and carbonate contents. This is possibly attributed to the easily dissolved and rigid features of carbonate, which can protect the primary interparticle pores due to its high compression resistance and is conducive to forming abundant dissolution pores. OM-rich carbonate-bearing mixed shale may be the most favorable lithofacies for gas storage in the northern Guizhou area.

In order to determine the optimum lithofacies for continental shale, the reservoir characteristics of different lithofacies types were studied based on a series of experiments. The lacustrine organic-rich shale of the Shahezi Formation is divided into siliceous (ORS), argillaceous (ORA), calcareous (ORC), and mixed (ORM) shales. The ORS, ORA, ORC, and ORM shales all carried out comprehensive reservoir comparative analysis. The results showed that the moderate content of clay minerals (45%) can significantly improve porosity, and high and low clay mineral contents are not conducive to the improvement of porosity. The ORM shale tends to have better pore connectivity than the ORS and ORA shales, and the ORC shale has the poorest pore-throat connectivity in micron-size. Internal pores in bitumen and clay shrinkage cracks are the dominant pore type and are well developed in ORS and ORM shales. The two types of pores are less developed in the ORA shale; however, dissolution pores are better developed than those of ORS and ORM shales. Inorganic pores are well-developed in the ORC shale, but organic pores are not. Organic and inorganic pores tend to be better connected in the ORM shale than those of the other three types, which could help improve the gas storage capacity. The ORM shale may have more irregular surfaces and lower liquid/gas surface tension. The higher capillary condensation on pore surfaces is more likely to occur in the ORA shale. The ORS shale offers fewer adsorption sites for CH4 and has lower adsorption capacity. The ORC shale has weak heterogeneity of the pore structure. Therefore, the ORM shale may be the most favorable lithofacies for shale gas enrichment and development, which has high porosity, good pore connectivity, moderate brittleness, and strong gas adsorption and storage capacity, followed by the ORS and ORA shales. The ORC shale is the worst.

A moisture equilibration test has been designed to study the pore structure and adsorption capacity of organic-rich shale with different moisture contents. Five humidity environments were artificially controlled to obtain shale samples with different moisture contents. With the moisture equilibration test and N2 adsorption/desorption, the differences in pore structure of samples with different moisture contents were compared and analysed. The results showed that the diameter of 2–10 nm pores decreased with increasing humidity and that the moisture adsorption characteristics conformed to the GAB adsorption model. It is proposed that when moisture enters a sample, monolayer adsorption will first occur because moisture is preferentially adsorbed on the pore surface with strong hydrophilicity, filling in the relatively small pores. Mesopores and micropores play a major role in water adsorption. With increasing humidity, capillary condensation of moisture gradually occurs in pores. Based on the methane isothermal adsorption test of shale samples with different moisture contents, a quantitative linear relationship between the moisture content and methane adsorption capacity of shale samples has been established. It has been determined that the methane adsorption capacity of shale in underwater conditions is less than that of dry samples, and that the rate of decline in the adsorption capacity of different samples under dry and water balance conditions varies greatly. The distribution characteristics of clay minerals are the main controlling factor of the hydrophilicity of shale, which has a certain guiding significance for further accurate evaluation of shale adsorption gas reserves.

The Carboniferous-Permian coal measures in China contain abundant natural gas resources. Shale, coal and tight sandstone reservoirs are developed in coal measures, and the quantitative characterization of the pore structures of different types of reservoirs can provide scientific guidance for the sweet spot prediction of tight reservoirs. In this study, taking the Shan 2 Member coal measure of the Shanxi Formation in the eastern Ordos Basin as an example, the pore structures of shale, coal rock and tight sandstone were systematically studied based on organic geochemistry, scanning electron microscopy, high-pressure mercury injection, and low-temperature N2 and CO2 adsorption experiments. The results show that the microscopic pore structures of different types of reservoirs in the Shan 2 Member coal measures are quite different. Shale and tight sandstone mainly develop clay mineral pores at mesopore scale, followed by intragranular and dissolution pores developed in quartz and feldspar minerals, while organic pores are rarely developed. A large number of macro-scale clay mineral pores and micro-fractures are developed in tight sandstone, meanwhile the pore connectivity of tight sandstone is better than that of shale. A large number of micro to nano-scale organic pores are developed in coal, and the specific surface area of micropores in coal is much larger than that of mesopores in shale and tight sandstone. Sandstone, shale, and coal are frequently interbedded in coal measure strata. Tight sandstone provide the main storage space for free gas, and pores in shale and coal absorb a large amount of natural gas. Sandstone-shale-coal assemblages and sandstone-coal assemblages are the key targets for the exploration of hydrocarbons in the Shanxi Formation coal measures in the study area.

In order to study the change of pore structure and adsorption characteristics of coking coal after the high-temperature and high-pressure adsorption test, the coking coal from the Liulin coalmine was selected for the research. Both the mercury injection experiments were carried out on the raw coal and the coal after the isothermal adsorption experiment processing with a pressure of 11 MPa and temperature ranging from 30 to 90°C. The results show that the pressure is beneficial to gas adsorption, while the temperature has a restraining effect on the gas adsorption of coking coal, and there is a good negative exponential relationship between the adsorption capacity and temperature. The hysteresis loop of that after the high-temperature and high-pressure isothermal adsorption test is smaller than that of raw coal, and the connectivity of pores becomes worse. In the process of the mercury injection experiment, the hysteresis loop of coking coal after the high-temperature and high-pressure adsorption experiment is smaller than that of raw coal. This demonstrates that the open pores decrease and the semi-closed pores increase, and then the connectivity of the pores becomes worse, which is not conducive to the gas flow when the coking is subjected to high-temperature and high-pressure action. After the high-temperature and high-pressure adsorption experiment, the volume of macropores, visible pores, and crannies of the coking coal decreases, and the volume of micropores and minipores increases. However, the total pore volume reduced overall. Under the same pressure, with the increase in temperature, the volume of macropores, visible pores, and crannies increases, while the volume of micropores and minipores decreases, and the total pore volume increases. After the high-temperature and high-pressure adsorption experiment, the proportion of micropores and minipores increases, and the specific surface area also increases. Under the same pressure, the surface areas of micropores and minipores decrease and the total specific surface area also decreases with the increase in temperature.

The southern Sichuan Basin is the core area of China’s efficient development of deep shale gas (burial depth greater than 3,500 m). Reservoir geological characteristics determine whether shale gas can be preserved, enriched, and produced. Taking the Long 11 sub-member of the Wufeng Formation of the Upper Ordovician and the Longmaxi Formation of the Lower Silurian in the East Weiyuan–North Rongchang area as an example, we used the core, logging, production test, and other data, combining X-ray diffraction analysis, LECO Total Organic Carbon (TOC)-S analysis, optical microscopy, and argon ion polishing field-emission scanning electron microscopy, to study the shale mineral composition, geochemistry, reservoir space, pore structure characteristics, and reservoir physical properties. The following results were obtained: 1) The brittle mineral content, organic matter maturity, and TOC content are high, gradually increase from top to bottom, and reach their maxima at small layer 1 of Long 11. 2) Organic pores, inorganic pores, and fractures are important reservoir spaces, among which organic pores and fractures are important seepage channels for shale gas. 3) The shale pore structure revealed by electron microscopy shows that the pore structure in target layers can be divided into four types: unimodal type (mainly organic pores), bimodal type (both organic and inorganic pores), monoclinic type I (mainly organic pores), and monoclinic type II (mainly inorganic pores). The pore morphology is complex, and circular and oval shapes predominate. 4) Sedimentary facies are the main factor controlling the enrichment of shale gas, and the development of fractures is the key to obtaining high yields of shale gas. 5) The class I favorable target area is mainly distributed in wells W206, W206H1, R234H, and R233H and areas to its south, and some areas in the east of the study area.

Although the southern Qinshui Basin is the most successful area for coalbed methane (CBM) development in China, the production of CBM wells in different blocks in the area is significantly different. One of the key reasons is the difference in pore structure in various-ranked coal. In this study, No. 3 coal seam of Sihe and Zhaozhuang blocks in southern Qinshui Basin was selected as the research object to investigate the high rank coal pore fracture structure and its impact on reservoir characteristics. Mercury intrusion porosimetry (MIP), low-temperature liquid nitrogen adsorption (LTN2A), scanning electron microscopy (SEM), and isothermal adsorption tests were conducted. The results show that the Sihe No.3 coal seam was mainly composed of open cylindrical and flat pores with a high proportion of transition pores (10–100 nm), large specific surface area, good connectivity, strong adsorption capacity, high gas content, and reservoir energy. Zhaozhuang No.3 coal had high proportion of mesopores (100–1,000 nm), small specific surface area, poor pores connectivity, weak adsorption capacity, poor gas content, low reservoir energy, and critical desorption pressure. The proportion of cylindrical pores, parallel plate pores, and wedge-shaped pores closed at one end was high. The anomalies in pore morphology and pore structure characteristics of coal reservoir were the main factors that caused variation in gas production of No.3 coal seam in Sihe and Zhaozhuang blocks.

With the development of unconventional oil and gas exploration “from sea to land,” lacustrine fine-grained sedimentary rocks (FSR) have gradually attracted the attention of scholars and become an important topic in the field of unconventional oil and gas, but the research is still in its initial stage. In this study, lacustrine FSR in the Dongying Depression of the Bohai Bay Basin are used as the research object, and nuclear magnetic resonance (NMR) and quantitative image characterization are used to characterize the pore structure of the reservoir in the study area on multiple scales, analyze the reservoir characteristics control factors, and classify and evaluate the reservoir. The results show that: 1) the favorable petrographic phases of the FSR reservoir can be classified into six types of organic-rich lime mudstone, organic-rich laminoid lime clay rock, organic-rich laminoid clay micritic limestone, organic-bearing banding clay micritic limestone, organic-rich banding lime clay rock, and organic-bearing lumpy clay micritic limestone. With an average porosity of 12.3% and an average permeability of 10.58 mD, the overall reservoir is a typical low-porosity-low-permeability type; 2) the reservoir space types are diverse, with strong microscopic inhomogeneity; pores with a pore size of less than 2 nm almost have no contribution to the reservoir space; the pore volume and pore area are mainly provided by organic matter pores at the 100 nm level, mineral intergranular pores, and clay mineral shrinkage pores/slits. The FSR reservoirs in the study area are classified into three categories, and the pore structure of the reservoirs from categories I to III deteriorates in turn. This study provides a basis for the microscopic characterization, classification, and evaluation of lacustrine FSR reservoirs and their exploration.

Shale samples with carbonate interlayers have attracted more and more attention in shale oil exploration of lacustrine shale in China, and the characterization of pore structure and wettability of these shales are significant to the study of shale-oil enrichment and effective exploitation. In this work, by examining six shale samples with carbonate interlayers of Shahejie Formation in East China, the pore structure and wettability characteristics of shale are characterized by means of thin section petrography; X-ray diffraction mineralogy; total organic carbon (TOC) analyses; scanning electron microscopy (SEM) imaging; air-liquid contact angle for wettability; as well as N2 physisorption, mercury intrusion porosimetry, and nuclear magnetic resonance (NMR) for pore structure. The results show that the main mineral contents are carbonate (with an average of 51.4%) and clay minerals (mainly mixed-layer illite-smectite). The average TOC content is 2.90%, and there is a strong correlation between TOC and dolomite content. In addition, the obvious layered structure is observed by thin section and SEM methods. The pores below 200 nm with ink-bottle shapes are obviously smaller than those of marine shale, and the pore throats are mainly below 50 nm; however, there are also some micrometer-sized cracks. The droplet contact angle measurement shows that the shale is mainly lipophilic, while moderately hydrophilic, at millimeter observational scales. The NMR T2 spectra of water- and oil-saturated samples have an obvious feature of three peak characteristics, as the pore size-associated wettability of these samples can be divided into three stages: water-wet (0.01–1 ms), oil-wet (1–40 ms), and mixed-wet (>40 ms) in terms of relaxation time of the NMR T2 spectrum. The proportion of the second main peak of T2 spectra (P2) for dodecane-saturated samples is directly proportional to the TOC content, and the relationship between P2 and mineral composition is consistent with water-saturated samples.

Microbially enhanced coalbed methane (MECBM) has important theoretical and practical significance for reforming coal reservoir structure, alleviating greenhouse effects and energy crises and developing new sources of clean energy. In this study, No. 3 coal seams in Qinshui Basin were taken as research objects to analyze the pore structure characteristics after microbial treatment by means of low-temperature nitrogen adsorption (LTNA), mercury porosimetry (MP), and isothermal adsorption/desorption experiments. The results showed that after bioconversion, the specific surface area and pore volume increased from 1.79 m2/g and 0.0018 cm3/g to 4.01 m2/g and 0.0051 cm3/g respectively under liquid nitrogen testing; however, the specific surface area was reduced from 5.398 m2/g to 5.246 m2/g and the pore volume was increased from 0.053 cm3/g to 0.0626 cm3/g under MP. The fractal dimension based on the LTNA data indicated that the fractal dimension of micropores and minipores was increased from 2.73 to 2.60 to 2.89 and 2.81, however the fractal dimension of meso-macropores was decreased from 2.90 to 2.85. The volatile matter and fixed carbon were both reduced from 6.68% to 78.63%–5.09% to 75.63%, and the Langmuir volume and Langmuir pressure were increased from 34.84 cm3/g and 2.73 MPa to 36.34 cm3/g and 3.28 MPa, respectively. This result indicated that microorganism participated in the degradation of coal reservoir and promoted the production of methane gas, the meso-macropores were more obviously modified by microorganism, so that the pore diameter stabilized, the pores became smoother, the specific surface area decreased, and the pore volume increased. These are more beneficial to the adsorption and production of coalbed methane (CBM) after microbial treatment.