In southern Sichuan Basin, the main production layers are characterized by deeply buried, high stress difference, and complex structural conditions. The Luzhou area is far from large faults, and natural fractures are greatly important for shale gas storage and production. Multi-scale natural fractures control the migration, enrichment, and preservation conditions of shale gas, and facilitate the formation of complex fracture network under the action of hydraulic fracturing. In this study, based on the outcrops, drilling cores, geochemical tests, thin section, and other experiments, the development characteristics of the Wufeng-Longmaxi shale in the Luzhou block, Southern China, are statistically analyzed, and the controlling factors (e.g., tectonic factors, organic matter, mineral components, mechanical properties) are discussed in details. Fractures observed in the outcrops are mainly regional fractures with two groups of orthogonal joints. Similarly, fractures observed in the core are also mainly joints fractures perpendicular to the laminae with three typical features (high-density, high-angle, and unfilled). In detail, steeply dipping fractures (75-90°) account for 78.1% of all fractures, with 85.1% being unfilled, 78.1% having a longitudinal extension less than 4 cm, and 65.1% having a spacing less than 2 cm. In brief, there exist cross-scale similarity among outcrops, cores, and microscopic thin sections, which is critical to the shale gas preservation conditions. Based on this understanding, further research is conducted on the relationship between the fracture density and gas content, which shows that (i) when the fracture density is less than 122 number/m, TOC content and fracture density together positively dominate gas content; (ii) when fracture density exceeds 122 number/m, gas content appears negative with fracture density, and TOC content is not the critical factor anymore. The above study establishes quantitative limits for shale gas preservation in the study block. It may assist in providing references for determining the sweet spot area and further deep shale gas exploration and development in the southern Sichuan Basin.

Knowledge of the present-day in situ stress field (PIS) has important theoretical and practical significance for shale gas exploration and development. The Wufeng-Longmaxi Formation in the Luzhou Block serves as the main reservoir of marine shale production in southern China. However, there is no clear understanding of PIS in the Luzhou area, which leads to a series of production problems. To investigate the PIS of deep shale reservoirs in Luzhou, experimental and finite element methods (FEMs) were used. Data obtained from imaging logging data, well deviation data, multipole array acoustic logging (XMAC), and world stress map were used to determine the orientation of the horizontal maximum principal stress (S _H max). Additionally, acoustic emission experiments were employed to determine the magnitude of three principal stresses. Based on FEM, with the stress of a single well as a constraint, a three-dimensional (3D) stress field model was developed. The results show that the orientation of S _H max varies from 90 to 120 °E. Further, there are significant differences in stress regimes across the region, with strike-slip/reverse faulting stress regime (S _H max > S _v ≈ S _h min) in the northern region and strike-slip stress regime in the southern region (S _H max > S _v > S _h min). In addition, geomechanical evaluations of wellbore stability and natural activation of fractures were performed. The Luzhou Block mainly develops two groups of natural fractures (NE-SW trending and NW-SE trending), with NW-SE trending being the dominant fracture development orientation. During the fracturing operation, a pore pressure increment larger than 50 MPa is conducive to maintaining a high opening ratio of the reservoir and improving the gas production efficiency. Horizontal wells drilled in the direction of maximum horizontal principal stress in the Wufeng-Longmaxi Formation reduce the probability of wellbore instability. The research results provide a reference for the effective development of deep shale gas reservoirs in southern Sichuan.

Herein, integrated vertical variation characteristic analysis was conducted by measuring total organic carbon (TOC), major and trace elements in Upper Ordovician-Lower Silurian (Wufeng-Longmaxi formations) black shale in Weiyuan, Luzhou, and Changning areas, southern Sichuan Basin to clarify the control of organic matter (OM) enrichment in different sublayers. According to the cycle boundary, it was divided into member 1 (submember 1 and submember 2) and member 2 from early to late Longmaxi formation, while it was divided into 4 sublayers from early to late during submember 1 depositional period. Under the warm and humid paleoclimate, high paleoproductivity, and gradually oxic paleoredox conditions, the TOC content (0.22-3.27 wt% in Luzhou area) in Wufeng formation increased gradually from early to late under the cocontrolling of tectonic framework and stagnant sea. After the glacial period, the warm and humid climate of Wufeng formation continued in Longmaxi formation, and TOC content reached the highest in sublayer 1 (2.02-4.02 wt%, 4.78 wt%, and 6.45 wt% in Weiyuan, Luzhou, and Changning areas, respectively), due to the high paleoproductivity and high sea level caused by melting glaciers, causing the extremely anoxic environment. The OM was preserved best. It remains higher in sublayer 2 (2.39 wt%, 3.69-4.18 wt%, and 3.5-3.86 wt% in three areas, respectively) because of the anoxic environment caused by deep water and the high paleoproductivity, but the temporary hot and dry environment has a certain negative impact on the OM preservation. Under the stable paleoproductivity, sublayer 3 has a character of water decreasing slowly, and the suboxic environment led to the decrease of TOC content (3.82-5.28 wt% and 3.77-4.13 wt% in Luzhou and Changning areas, respectively). Meanwhile, that in the yuan area became deeper and the TOC content became relatively higher (1.92-3.33 wt%). Under the open environment, sublayer 4 was controlled by lower sea level caused by regression, resulting in lower TOC content (1.31-4.57 wt%, 1.64-3.52 wt%, and 3.88-4.49 wt% in three areas, respectively). However, the global regression of the submember 2 period, high terrigenous debris dilution, and oxic environment lead to the no preservation of OM. Generally speaking, the enrichment of OM is not only affected by the changes of global sea level and paleoproductivity to some extent (Longmaxi shale) but also controlled by the tectonic framework in Sichuan Basin (Wufeng shale). The findings of this study can help for a better understanding of the OM enrichment mechanism and provide a theoretical basis for the evaluation of high-quality source rocks.

Wells with low gas content and low resistivity in the Changning area, southern Sichuan Basin were selected for this study. The burial-thermal history was reconstructed and the characteristics of multi-phase fluid activity were clarified using microscopic observation and testing of fluid inclusions in the Longmaxi shale fracture veins. Compared with wells with a high gas content and high resistivity, the influence of fluid activity on resistivity was analyzed. The results showed that the thermal evolution of the bituminous inclusions trapped in the veins has reached the stage of carbonaceous-metamorphic bitumen, and the organic matter is fully cracked for gas generation, with some organic matter exhibiting the phenomenon of “graphitization.” The synchronous fluid with bitumen was existed due to shallow burial with a middle-low maturity stage of about 280 and 292 Ma. Two phases of fluids existed in the deep burial stage, thus maturing for about 103 Ma, and the uplift stage at about 28 and 32 Ma, with high homogenization temperatures (Th) (varying from 185 to 195°C and 165–180°C). The corresponding pressure coefficients varied between 1.67 and 2.09, 1.56 and 1.92 in a moderate-strong high-pressure state. The last two phases of fluid formation in the late uplift stage for about 4 to 19 Ma and 6 to 10 Ma were characterized by low salinity at medium-low Th (varied from 140 to 155°C and 120–135°C), with pressures of 57.47–74.50 MPa and 51.44–59.41 MPa (pressure coefficients of 1.09–1.41 and 1.18–1.37), in an atmospheric-weak overpressure state. In the initial uplift stage after deep burial, the fluid closure in the Changning area was good. In contrast, the wells are filled with low gas content because of the strong tectonic forces causing the shale gas to be released and the multi-phase fluid activity that happens during the late uplift stage. New evidence indicates that the emergence of low resistance in the localized Changning area is not only related to the high degree of evolution of organic matter but is also affected by the multi-phase fluid modification in the late uplift stage.

Twelve shale fracture veins and forty-nine fluid inclusion assemblages within the veins of 3800-4200 m in three wells located in different tectonic zones in the Yuxi Region, southern Sichuan Basin were selected in this study. The burial and thermal histories of single wells were reconstructed, and time- temperature-pressure of oil and gas filling were clarified using microscopy observation, Raman microprobe analyses, geochemical tests, and fluid inclusion microtemperature measurement. The shale fracture veins of the Wufeng-Longmaxi Formation in the Yuxi Region are mainly formed vertically and horizontally, where the vein-forming fluids are derived from endogenous fluids. A large number of methane inclusions, bituminous inclusions, and methane-bearing bituminous inclusions within the veins confirm the process of oil cracking gas and kerogen cracking gas. The homogeneous temperature (Th) of the aqueous inclusions contemporaneous with the bituminous inclusions ranges from 109.3 to 174.1 degrees C, which were trapped during 220 to 250 Ma. The homogeneous temperature of the aqueous inclusions contemporaneous with the methane inclusions ranges from 137.3 to 226.8 degrees C, which were trapped during 160 to 195 Ma and 51 to 56 Ma. The trapped pressure calculated by high-density methane inclusions (0.246-0.293 g/cm(3)) is between 82.9 and 140.1 MPa, with a pressure coefficient between 1.64 and 2.07. The formation pressure coefficient is nearly two, indicating that the current overpressure is inherited from the overpressure at the maximum burial depth. The earlier the fracture vein opening, the less the damage to the shale gas accumulation, and the more opening-dosing phases, the lower the homogeneous temperature of the gas-liquid two-phase aqueous inclusions coeval with the high-density methane inclusions and the greater the degree of damage to the shale gas accumulation. The results provide a basis for further study on the genesis of overpressure and the migration of shale gas.