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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]

In the Luzhou Block of the southern Sichuan Basin, the deep Longmaxi shales have become important exploration targets in recent years. However, the water-bearing properties of these shales are still unclear, which significantly limits evaluations of reservoir pore structures and gas-in-place (GIP) contents. In this study, twelve fresh shale core samples were collected at the well site, and the pore water (CPW) and equilibrium water (CEW) contents, as well as the pore structures of the shales, were analyzed under both as-received and dried conditions. The results indicate that the deep shales have low water-bearing extents with a pore water content (CPW) of 3.82–16.67 mg/g, and that both the organic matter (OM) and inorganic matter (IM) pores can be used for pore water storage. The extent of influence of pore water on nonmicropores and IM pore structures is more significant than that on micropores and OM pore structures. Meanwhile, the pore water obviously reduces the retention effects of nanopores and may block nanopores with pore widths < 0.5 nm. An average of 40% of pore spaces were taken up by pore water in the studied deep shales in the Luzhou Block, and the residual pore surface area and pore volume of the shales were mainly contributed from micropores and nonmicropores, respectively. [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]

There are various sedimentary structures developed in the black shales of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation in Luzhou area, southern Sichuan Basin, southwestern China. In order to evaluate the controlling effects of sedimentary structures on the key parameters of shale reservoir properties, collected classification of sedimentary structures, scanning electron microscope observation, analysis of shale fabric and porosity characteristics, low‐pressure nitrogen adsorption, methane isothermal adsorption, and conventional triaxial compression test were carried out based on shale samples from Wells A‐H1, B‐H1, C‐H1 and D‐H1 in the study area. The sedimentary structures recorded in these shales are categorized into five types: homogeneous bedding, weak horizontal bedding, strong horizontal bedding, discontinuous ripple bedding, and gravel‐bearing massive bedding. In general, the palaeo‐hydrodynamics and oxygen content of water columns were weak when homogeneous bedding shale was deposited. The organic matter is the most abundant and the total organic carbon content is up to 4.01% on average. The average quartz content is 43.5%, and the brittleness index is the highest. The porosity and adsorption capacity were the highest, with an average of 4.57% and 79.5 scf/ton, respectively. Combined with its mechanical properties of low Poisson's ratio and high Young's modulus, homogeneous bedding sedimentary structure is associated with the shale units possessing the highest organic matter abundance, the strongest reservoir property, and the best fracability, which is the priority target for exploration and development of the Wufeng to lower Longmaxi Formation in the Sichuan Basin, southwestern China. [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 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]

In order to improve the seepage channels in shale, soaking operation is often conducted after fracturing to carry out full shale hydration by the fracturing fluid. Previous research has mainly focused on the changes in the overall pore volume of shale due to hydration, but there is a lack of understanding on the volume changes of varied-size pores during the hydration process. In this study, a nuclear magnetic resonance (NMR) measurement method was carried out to obtain the size distribution of the pores in the shale in its unaltered state using ethanol as the saturation medium. Subsequently, through experiments, the shale core was saturated with fracturing fluid, and the dynamic changes in the pore size distribution under hydration were monitored using the low-field NMR technique. In addition, the relationships between the type of clay, the salinity of the fracturing fluid and the volume changes of varied-size pore were analyzed. The results of this study indicate that when the shale and fracturing fluid underwent hydration, the increase in the volumes of varied-size pores was concentrated in a certain pore-size area. This pore -size area was related to the type of clay that the shale contained. There was a strong correlation between the mixed-layer illite-smectite content and the increase in the small meso-pore volume. And the same between the illite content and the increase in the micro-pore volume. The saline fracturing fluid had an inhibitory effect on the shale hydration, mainly in the micro-pore domain. The results of this study is significant to optimize the selection of shale gas reservoirs and fracturing fluids for use in soaking measures. • A NMR method was proposed to obtain the unaltered pore-size distributions in shale. • The relationship between the type of clay and increasing pore-size was obtained. • The inhibitory effect of high-salinity solution mainly occurs in the micro-pores. [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]

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]

At present, the stimulation technique involving soaking after fracturing of shale gas reservoirs has received increasing attention. In this study, gas-water displacement experiments were carried out to simulate the contact state between the fracturing fluid and the shale during the soaking stage after hydraulic fracturing of the shale gas reservoir. By using low-field nuclear magnetic resonance to dynamically monitor the occurrence state of the methane in shale cores, the changes in the masses of the methane in different occurrence states were calculated. Furthermore, the displacement of the adsorbed methane in the shale by the fracturing fluid was studied. In addition, the influences of the fracturing fluid's salinity and the shale clay content and type on the displacement process were also analyzed. The results of this study show that the fracturing fluid has a stronger adsorption on clay minerals than that of methane, so it can replace the adsorbed methane in the shale. Compared with pure fracturing fluid solution, the high salinity fracturing fluid solution containing cations has a stronger adsorption on the clay minerals in the shale, and thus, it has a stronger displacement ability. The mineral composition of the shale reservoir also has an important influence on the displacement efficiency. The higher the content of clay minerals with high adsorption capacities, the more adsorbed methane is replaced. The results of this study are important for gaining a better understanding of the stimulation technique involving soaking after fracturing of shale gas reservoirs and for optimizing the design of soaking. • The fracturing fluid can displace the methane adsorbed in the shale during soaking. • A high-salinity fracturing fluid has a stronger displacement ability. • The relationship between the mass of the adsorbed methane and time was obtained. [ABSTRACT FROM AUTHOR]

Based on low-temperature thermochronological data (i.e., apatite fission-track (AFT) and (U–Th)/He (AHe)), structural evolution, burial and thermal history, this paper examines the relationship of multi-stage evolution between the upper Ordovician Wufeng and lower Silurian Longmaxi formations (i.e., the WL formation) and rapid exhumation at the Changning shale gas field in the southern Sichuan basin. AFT ages are generally young from southeast to northwest, decreasing from ca. 40 to 15 Ma while AHe single-grain ages range from ~35 to ~5 Ma. Inverse thermal histories show that a multi-stage cooling history with initial cooling began in the Late Cretaceous to early Cenozoic (middle Eocene), followed by accelerated rapid cooling in the late Cenozoic, with cooling rates of 2–4 °C/Myr across the Changning shale gas field. In particular, thermal models of samples in the western Changning area show a substantial increase in the cooling rates, i.e., from less than 1 °C/Myr to 3–5 °C/Myr in the Miocene. Integrated with inverse T-t models of low-temperature thermochronological data, the burial history indicates a four-stage thermal evolution of the WL Formation in the Changning shale-gas field: Early Mature from the middle Silurian to middle Permian, Middle Mature from the late Permian to Late Triassic, Late Mature from the Early Jurassic to Early Cretaceous, and Over mature since the middle Cretaceous, reaching a maximum burial depth of ~6000 m and maximum temperature of 190–200 °C at ca. 70–80 Ma. This evolution further suggests that a normal hydrostatic pressure index dominated the WL Formations in the Paleozoic. The gas generation and pressure index, however, have substantially increased since the Late Jurassic, particularly from the Early to middle Cretaceous, with a maximum pressure index of 2.1, which is indicative of the main shale gas accumulation and enrichment period in the WL Formation. Post-gas-generation structural deformation, uplift, and exhumation had a significant impact on shale gas enrichment, mainly through their influence on shale gas preservation. This suggests some relationships among the higher pressure coefficient of the WL Formation, the higher productivity and total gas content of the WL Formation, a weaker post-gas-generation structural deformation, and a weaker uplift, as indicated by the erosion and burial depth across the Changning shale gas field. Due to a significantly stronger cooling and uplift that occurred the in Late Cenozoic across the western Changning area, the pressure index decreased rapidly from ~2.0 to 1.0 with a normal pressure condition, indicating the destruction of the reservation condition in the WL Formation. • New low-temperature thermochronological data was from the SE Sichuan basin. • An accelerated cooling in the late Cenozoic was found. • Post-gas-generation deformation and exhumation controlled the shale gas enrichment. [ABSTRACT FROM AUTHOR]