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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]

The Wufeng-Longmaxi Formation shales with burial depths > 3 500 m in the southern Sichuan Basin are believed to have large shale gas potentials. However, the reservoir properties and gas-in-place (GIP) contents of these shales exhibit variations across different sublayers. In this study, a set of Wufeng-Longmaxi shales with burial depths of 4 000–4 200 m was derived from the Well Y101H2 in the Luzhou area, and the differences in geological and geochemical characteristics, porosity, water saturation and GIP content of various sublayer shales were investigated. The results indicate that the TOC content and effective porosity of the upper (LMX1-4) and lower (LMX1-3) sublayer shales of the first member of the Longmaxi Formation are better than those of the Wufeng Formation (WF) shales, which results in the LMX1-4 and LMX1-3 shales having higher GIP contents than the WF shales. The GIP contents of the LMX1-3 shales are higher than those of the LMX1-4 shales, and this is likely because the organic matter of the LMX1-3 shales had more aquatic organisms and was preserved in a stronger reductive environment, which leads to a stronger gas generation potential. In contrast to the middle-shallow LMX1-4 shales in the Sichuan Basin, the deep LMX1-4 shales in the Luzhou area have advantageous reservoir properties and GIP contents, and thus it is promising to synchronously exploit the deep LMX1-4 and LMX1-3 shales in some regions of the southern Sichuan Basin. [ABSTRACT FROM AUTHOR]

Fluid charging and formation pressure evolution are of great significance for shale gas exploration and development. Taking the Longmaxi formation shale in southeast Chongqing as the research object, the fluid activity and pressure evolution process were studied by means of thin section observation, fluid inclusion analysis and testing, and basin numerical simulation. The results show that the area of the southeast of Chongqing, the Longmaxi formation of dike filling minerals, is mainly quartz vein and calcite part of the veins and arteries, and vein body captures the rich organic inclusions in minerals, sees fgas-liquid two-phase brine inclusions and methane inclusions, combining with the temperature and salinity of brine inclusions, and shows that the area has experienced two phases of oil and gas filling, the first period of gas-liquid fluid. The second stage is gas fluid. Combined with burial history and thermal maturation history, it is found that the filling time of oil and gas is late Cretaceous and Paleocene, respectively. In the Cretaceous, the pressure coefficient of Longmaxi formation reached the maximum value of 2.2 and remained above 1.5 overpressure after pressure unloading in the later period. In terms of the frequency of inclusions, the charging amount of the first stage is relatively large, and the charging time corresponds to the peak period of the palaeo-formation pressure. At the same time, fluid charging can timely supplement the pressure after unloading, which is conducive to high and stable production of shale gas. [ABSTRACT FROM AUTHOR]

The shale of the Lower Silurian Longmaxi Formation is an important gas-producing layer for shale gas development in southern China. This set of shale reservoir characteristics and shale gas development potential provide an important foundation for shale gas development. This study takes wellblock XN111 in the Sichuan Basin, China, as an example and uses X-ray diffraction (XRD), scanning electron microscopy (SEM), isothermal adsorption, and other techniques to analyze the shale reservoir characteristics of the Lower Silurian Longmaxi Formation. The results show that the Lower Silurian Longmaxi Formation was deposited in a deep-water shelf environment. During this period, carbonaceous shale and siliceous shale characterized by a high brittle mineral content (quartz > 40 wt. % , carbonate mineral > 10 wt. %) and a low clay mineral content (<30 wt.%, mainly illite) were widely deposited throughout the region. The total organic carbon (TOC) content reaches up to 6.07 wt.%, with an average of 2.66 wt.%. The vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The methane adsorption capacity is 0.84–4.69 m3/t, with an average of 2.92 m3/t. Pores and fractures are developed in the shale reservoirs. The main reservoir space is composed of connected mesopores with an average porosity of 4.78%. The characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation are controlled by the following factors: (1) the widespread deep-water shelf deposition in wellblock XN111 was a favorable environment for the development of high-quality shale reservoirs with a cumulative thickness of up to 50 m; (2) the high TOC content enabled the shale reservoir to have a high free gas content and a high adsorptive gas storage capacity; and (3) the shale's high maturity or over maturity is conducive to the development of pores and fractures in the organic matter, which effectively improves the storage capacity of the shale reservoirs. The reservoir characteristic index was constructed using the high-quality shale's thickness, gas content, TOC, fracture density, and clay content. Using production data from shale gas wells in adjacent blocks, a mathematical relationship was established between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristics Index (Rci). The EUR of a single well in wellblock XN111 was estimated. [ABSTRACT FROM AUTHOR]

The characterization of organic nanopores across the entire range is essential for gas storage and productivity evaluation of marine shale. To achieve a precise and comprehensive analysis of organic nanopore properties, an integration method of helium ion microscope (HIM) and scanning electron microscope (SEM), as well as focused ion beam-HIM (FIB-HIM) and FIB-SEM, was proposed. This integration method extends the organic pore imaging and quantitative analysis to below 10 nm. Results demonstrate that organic pores below 10 nm significantly impact the evaluation of shale gas storage and productivity by contributing to the porosity and specific surface area and altering pore size distribution and connectivity characteristics. The surface porosity increases by 10.73%, while the specific surface area increases by 76% according to the integration method. The integrated pore size distribution converts the unimodal PSD from the stitched SEM mosaic to a multimodal PSD, supporting the multi-stage formation mode of organic nanopores: larger bubble pores appear with oil generation at the early stage, while smaller spongy pores appear with gas generation at the later stage. The organic pores revealed by FIB-HIM have higher coordination numbers and a higher proportion of inner-connected volume, showing the more complex connectivity characteristics. Despite limitations due to heterogeneity and inadequate resolution, these novel insights by the integration method highlight the importance of exploring organic pores at the nanoscale and have the potential to inform further research in this field. • Organic nanopore size distribution in marine shale is corrected to a multimodal curve by the integration of HIM and SEM. • Organic nanopores beyond the SEM resolution significantly impact the evaluation of shale gas storage and productivity. • The integration of HIM and SEM provides more accurate and representative characteristics of organic pores in marine shale. [ABSTRACT FROM AUTHOR]

The lower Silurian Longmaxi Formation hosts a highly productive shale gas play in the Zhaotong region of southern China. According to core observation, X-ray diffraction analyses, and scanning electron microscopy (SEM) observations, the shale comprises primarily quartz, carbonate minerals, and clay minerals, with minor amounts of plagioclase, K-feldspar, and pyrite. The clay mineral content ranges from 15.0% to 46.1%, with an average of 29.3% in the Zhaotong region. Organic geochemical analyses show that the Longmaxi Formation has good potential for shale gas resources by calculating total organic carbon, vitrinite reflectance, and gas content. Scanning electron microscope images demonstrate that reservoir pore types in the Longmaxi shale include organic pores, interparticle pores, intercrystalline pores, intraparticle pores, and fractures. Reservoir distribution is controlled by lithofacies, mineral composition, and geochemical factors. In addition, we investigated the relationships between reservoir parameters and production from 15 individual wells in the Zhaotong region by correlation coefficients. As a result, the brittleness index, total organic carbon (TOC), porosity, and gas content were used to define high-quality reservoirs in the Longmaxi shale. Based on these criteria, we mapped the thickness and distribution of high-quality reservoirs in the Longmaxi Formation and selected highlighted several key sites for future exploration and development. [ABSTRACT FROM AUTHOR]

Currently, Luzhou in the Sichuan Basin is a focal point for shale-gas exploration and development in China. However, a lack of detailed research on the mineral composition of the Wufeng Formation-Longmaxi Formation (WF-LF) shale is hindering the extraction of deep-buried shale gas in the Luzhou shale play. Herein, a field emission scanning electron microscope (FESEM) equipped with the Advanced Mineral Identification and Characterization System (AMICS) software was employed to analyze the mineral composition of the WF-LF shale from six wells in Luzhou. Quartz was the dominant mineral type, (16.9–87.21%, average 51.33%), followed by illite, calcite, dolomite, and pyrite. Our study revealed that (1) quartz content showed a moderate positive correlation with the total organic carbon (TOC) content, indicating that the quartz found in the shale is mostly of biological origin; and (2) the sum content of siliceous minerals and carbonaceous minerals was moderately positively correlated with the brittleness index (BRIT) in well SS1H2-7 and in the well group of RS8 and RS5, indicating that the siliceous minerals and carbonaceous minerals had an active effect on reservoir compressibility. Finally, according to the mineralogical features of each sublayer, we identified four types of reservoirs to determine their scope for exploration. [ABSTRACT FROM AUTHOR]

In this study, shale cores from 20 wells in the S1l11-1 sublayer of Longmaxi Formation buried in shallow shale (<3500 m) and deep shale (>3500 m) in the southern Sichuan Basin, China were collected to compare their pore structures and gas-bearing properties using multiple experiments. Results showed that the deep layer has relatively lower brittle mineral content, which is disadvantageous in terms of the higher requirements it imposes on hydraulic fracturing. Results also showed that the most important factor controlling the differential enrichment of S1l11-1 shale gas in southern Sichuan Basin is porosity. Moreover, the porosity composition of shallow shale and deep shale has significant differences: the porosity of shallow shale is dominated by organic pores, while for deep shale, both organic and inorganic pores are important. The inorganic pores provide significant storage space for free gas in deep shale; their contribution warrants more attention. We also found that the difference in organic porosity of the shallow and deep shale samples resulted from large differences in pore development ability, while the highest inorganic porosity was concentrated near the optimal mineral composition when the content of quartz plus feldspar plus pyrite was about 70%. This study revealed the primary factor controlling the difference in gas content between shallow and deep shale and detailed the characteristics of microscopic pore structure, providing a basis for the exploration and development of deep shale gas in the Wufeng-Longmaxi Formation in the southern Sichuan Basin. [ABSTRACT FROM AUTHOR]

The pressure decay (or gas expansion) test with crushed samples has been used to evaluate the matrix permeability of shale and other low-permeability rock for many years. However, there still exist uncertainties relating to particle size and equilibrium pressure. The existing late-stage curve fitting method has the advantage of easy calculation, but the assumption that gas enters particles with a single permeability value is not generally applicable for shale samples, and late-stage analysis may lead to underestimation. This study proposes an optimization method to determine the equivalent bulk permeability that ensures the smallest sum of squares of errors between the forward-predicted pressure decay curve and the measure one. Both the optimization and curve fitting method are applied to two shale samples from the Ordovician Wufeng Formation of two wells in the Sichuan Basin, China with improved apparatus and testing procedures. The optimization method is superior to the curve fitting method in the repeatability and regularity on the change of apparent permeability with pressure. A strong linear relationship between apparent permeability and coefficient of compressibility is established between 3 and 12 bars. The variation of permeability with particle size is more diverse than that is commonly understood and might be nonmonotonic, depending on the change of pore structure during crushing. Change of apparent permeability with pressure (non-Darcy feature) is proposed as a criterion of whether pore structure has changed significantly. It is suggested to measure the variation of permeability with pressure and particle size to obtain a more comprehensive understanding of matrix permeability and pore structure. • An optimization method that ensures the smallest sum of squared errors is proposed. • The optimization method shows a better repeatability and more obvious regularities. • A linear relationship between permeability and compressibility is established. • Non-Darcy feature is proposed as a criterion of whether pore structure change. • Permeability might vary with particle size non-monotonically. [ABSTRACT FROM AUTHOR]

The permeability of shale in unconventional subsurface reservoirs under high-temperature and high effective stress conditions is of great significance for evaluating the extraction efficiency of shale gas and determining reservoir development programs. In this study, a series of permeability experiments using nitrogen gas were conducted on a sample from the lower Longmaxi Formation over a range of temperature (25–100 °C), effective stress (22.5–52.5 MPa), and pore pressure (0.5–8 MPa) conditions. The dynamic relationships between permeability and temperature, effective stress, and pore pressure are analyzed in detail. The results show that the apparent permeability decreases approximately linearly with increasing pore pressure, temperature, and effective stress. The absolute permeability also decreases with increasing temperature or effective stress. Upon increasing the reservoir depth by 1000 m , the permeability decreases by an average of approximately 25%. Approximately two-thirds of this decline is caused by changes in the effective stress and approximately one-third by changes in temperature. The Klinkenberg parameter is also found to be positively correlated with temperature and effective stress. The results herein provide important guidance for evaluating permeability changes and the extraction efficiency for deep shale gas development. • The shale permeability was measured at different pressure and temperature. • The Klinkenberg parameter is positively correlated with temperature and stress. • A model is developed to describe the gas permeability with respect to burial depth. [ABSTRACT FROM AUTHOR]

[Display omitted] • The shale gas resource potential of the Longmaxi Formation was evaluated by using mud gas isotope logging technology. • The reservoir properties of shale were evaluated based on gas isotope fractionation effects. • The shale gas in the Changning area belongs to late kerogen cracking gas. • The lower part of the Longmaxi Formation has a better shale gas exploration potential. The Longmaxi Formation in the Sichuan Basin is one of the most important shale gas producing formations in China. Previous studies of shale gas were mostly carried out on based on laboratory analyses and did not provide effective guidelines for shale gas exploration. In this paper, we present a large amount of carbon isotopic data from mud gas isotope logging and rock-cutting headspace gas in wellsites. The δ13C 1 values showed a significant decrease at the bottom of the Longmaxi Formation. The δ13C 1 and δ13C 2 values in the Changning area were observed to be heavier than those in the Weiyuan and Jiaoshiba areas. The second half of the N216H27-3 horizontal well had obvious outgassing and carbon isotope fractionation effects. This indicates that the bottom of the Longmaxi Formation has better shale gas exploration potential. The shale gas of the Longmaxi Formation in the Changning area belongs to late kerogen cracking gas, where exploration prospects are poorer than those in the Weiyuan and Jiaoshiba areas. There were more oil cracking gas resources and better reservoir conditions at the end of the N216H27-3 horizontal well; therefore, drilling should be continued at this site. [ABSTRACT FROM AUTHOR]

• High-pressure methane adsorption isotherms of 106 Wufeng-Longmaxi shales are measured. • Organic matter and clay are main compositions controlling factors of methane adsorption. • The isotherm of a shale is a linear superposition of those of its organic matter and clay. • V L , P L and ρ ads are found to be definite but different for unit organic matter and clay. • A quantitative composition-based model for adsorbed methane amount are proposed. The Wufeng-Longmaxi Formation shale in Sichuan Basin is the main strata of shale gas exploration and development in China. Adsorbed methane is an important part of the total shale gas content. The influence of shale composition on adsorption characteristics is complex, and it is difficult to obtain a comprehensive understanding without a sufficient amount of data. In this work, the total organic carbon (TOC), X-ray diffraction (XRD) mineral analysis, and the excess methane adsorption isotherms with pressure up to 50 MPa at 40 °C of 106 overmature shale samples with TOC of 0.8%-9.0% and clay content of 2%-58% that belong to Wufeng-Longmaxi formation from 10 shale gas wells in Sichuan Basin, China are experimentally investigated and analyzed. New correlations found between compositions and methane adsorption characteristic parameters guide the establishment of a composition-based methane adsorption model that the excess adsorption isotherm of shale is the content-weighted sum of equivalent unit-content excess isotherms for organic matter and clay. With this model, the differences of excess isotherms of these two compositions and the differences of clay-contribution to methane adsorption for different sublayers are disclosed. It is beneficial to improve the accuracy of shale reservoir evaluation of studied blocks under the condition of limited coring and deepening the understanding of the underlying mechanism of methane adsorption characteristics. [ABSTRACT FROM AUTHOR]

Although substantial advances have been made in investigating the storage and transport properties of shale gas in past decades, understanding of the flow characteristics and gas-bearing property in organic pores remains limited. In this paper, organic pores in the organic matter (OM) of the marine Longmaxi Formation are classified into six types based on the morphology and sizes of nanoscale pores. The structures of the six types of typical organic pores under high temperature and pressure are investigated based on the digital core compressibility method introduced in this paper. The results show that the pore-size distribution and connectivity of organic pores under high temperature and pressure are considerably different from those under conventional conditions. The apparent permeability of OM with different proportions of macropores, mesopores, and micropores are analyzed. The results demonstrate that the permeability of OM with Type 1 organic pores has the largest changes after compaction, whereas OM with Type 5 organic pores has a relatively smaller change. The regularities of the absolute adsorption amount and the free gas amount of OM with typical organic pores are also investigated. The absolute adsorption amount of OM decreases with the proportion of macropores, whereas the amount of free gas of OM increases. Finally, a chart of the absolute adsorption amount and the free gas amount of OM at different depths is given, which is helpful for estimating the gas-bearing capacity of OM and preliminary understanding the quality of a shale reservoir. • Organic pores in OM are classified into six types based on the morphology of organic pores. • A digital core compressibility method is introduced to study shales under reservoir condition. • The apparent permeability of typical organic pores under reservoir condition are investigated. • The charts of the gas-bearing capacity for organic pores at different depth are presented. [ABSTRACT FROM AUTHOR]