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Due to global geological events and differences in regional sedimentary environments, marine shale reservoirs of Wufeng-Longmaxi Formation in Eastern and Southern Sichuan Basin exhibit significant heterogeneity in organic matter content and mineral composition. In order to reveal the influence of paleoenvironment evolution on reservoir heterogeneity, key geochemical indicators of elements were used to reconstruct the sedimentary environment of marine shale in Eastern and Southern Sichuan Basin. The influence mechanism of paleoenvironment on organic matter content and mineral components was also explored. The results indicate that the Wufeng-Longmaxi Formation in the Southern and Eastern Sichuan Basin can be divided into two third-order sequences (Sq 1 and Sq 2). Each third-order sequence is divided into a transgressive system tract (TST) and a highstand system tract (HST). The average TOC content in the Eastern Sichuan Basin is the highest during the TST1 period with reaching 4.2%, while reached its maximum at 3.9% during the TST2 period in the Southern Sichuan Basin. Due to the influence of high paleo-productivity, the organic matter accumulation and quartz content in the eastern Sichuan region were higher than those in the southern Sichuan region from the TST1 to the middle TST2 period. However, the organic matter accumulation and quartz content in the late TST2 period were lower than those in the southern Sichuan region due to the dilution of terrestrial debris. During the HST2 period, due to the influence of higher paleo-productivity, clay adsorption and preservation condition, the TOC content in the eastern Sichuan region slightly increased in the early stage. At the same time, the marine shale in the southern Sichuan region has a high content of quartz minerals and a low content of clay minerals due to strong weathering intensity and input of coarse-grained debris (silt-size quartz).

As an important target for deep to ultra-deep carbonate oil and gas exploration, Fractured-Vuggy dolomite reservoirs have strong heterogeneity. Accurate characterization of reservoir facies is crucial for their exploration and exploitation. Three methods, including the unsupervised intelligent clustering method of improved Fuzzy C-means clustering Algorithm Based on Density Sensitive Distance and Fuzzy Partrition (FCM-DSDFP), the fusion method of Principal Components Analysis (PCA) dimensionality reduction and noise reduction, and the principle of clustering feature analysis are applied to identify reservoir facies based on logging data. Based on the PCA method, the logging response characteristics of the reservoir facies are excavated, and the fusion characterization data of dimensionality reduction and noise reduction are extracted. The FCM-DSDFP unsupervised intelligent clustering method, a model that approximates the subsurface conditions is established, and the reliability of the model is tested according to the elbow rule and silhouette coefficient. Combining drilling core observation, Fractured-Vuggy type, partially cemented Fractured-Vuggy type, Pore-Vuggy type, Pore Type I, Pore Type II, Tight Type I, and Tight Type II are divided in the Dengying Formation 4th Member. Fractured-Vuggy type, partially cemented Fractured-Vuggy type, Pore-Vuggy Type I, Pore-Vuggy Type II, Pore Type I, Pore Type II, and Tight Type are divided in the Dengying Formation 2nd Member, respectively. Two methods were applied to verify the reservoir facies identification results based on intelligent algorithms. The first method is to compare the identification results with the reservoir facies types identified by core observations (Well PT103 and PS13). The second method is to verify the recognition results of intelligent algorithms by utilizing the relationship between reservoir facies types and bitumen. The test results show that the accuracy of the reservoir level identification is higher than 0.9, and the applicability is better than the commonly used algorithms such as FCM and K-means.

The lacustrine shale, represented by the Lianggaoshan Formation, is widely distributed in oil and gas basins of China and will be a key target for unconventional hydrocarbon exploration in the future. Due to the complexity of geological conditions, the distribution of lacustrine shale and the mechanism of organic matter (OM) enrichment show significant differences between different basins. In this study, seismic interpretation, core observation, high-frequency geochemical analysis and other methods are integrated to reveal factors controlling lacustrine shale distribution and OM accumulation in lacustrine shale. The results suggest that six bottom-to-top organic-rich shale intervals are identified within the Lianggaoshan Formation due to lake-basin migration. The migration process of depocenters controls the planar distribution of lacustrine organic-rich shale. The organic-rich lacustrine shale within 1st Member and 2nd Member is characterized by relatively high paleoproductivity and dysoxic condition. The lacustrine organic-rich shale of the upper to the top of 3rd Member is characterized by relatively low paleoproductivity, relatively high terrestrial input, and dysoxic condition. Paleoproductivity and preservation condition caused by lake-level rise are generally the major influencing factor of organic matter accumulation in 1st Member and 2nd Member organic-rich shale. The input of terrestrial OM, and the condition of preservation caused by rapid deposition are the major factors controlling OM accumulation in 3rd Member of Lianggaoshan Formation.

The unconnected gas-bearing pores in shale gas reservoirs may be transformed into “potential recoverable pores” after large scale hydraulic fracturing. However, the mainstream pore classification methods of shale gas reservoirs, do not take the unconnected pores into account, which impacts the evaluation accuracy of reservoir pore effectiveness. To solve this problem, this paper took the shale of Lower Silurian Longmaxi Formation in the southern Sichuan Basin as the research object to carry out experiments on core porosity, centrifugal + gradual drying NMR after saturated with brine and NMR freeze–thaw using plunger samples and crushed samples to analyze the volume, main development location and main pore size distribution range of unconnected pores. Then, the pore systems were classified, and the lower limit of effective pore size of connected gas-bearing pores was determined. Finally, the total pore effectiveness of shale gas reservoirs was evaluated, and the influence of unconnected pores on the development of shale gas was discussed. And the following research results were obtained. First, there are a large number of unconnected pores in the shale gas reservoirs of the study area, accounting for 30.23%. Most of them are mainly developed in organic matters and a few are developed in clay minerals. The distribution of pore size ranges from 5 nm to 30 nm. Second, T2 cut-off value of clay bound water in the shale gas reservoirs of the study area is 0.26 ms, whose corresponding pore size is 5.35 nm, which is the lower limit of the effective pore size. Third, large-scale hydraulic fracturing can improve the unconnected pores with the size more than 5.35 nm, so effective development of shale gas will be realized. Fourth, after hydraulic fracturing stimulation, the unconnected pores can increase the storage space of fracturing fluid in the matrix, absorb the fracturing fluid in the fractures, replace the shale gas in the pores and promote the automatic alleviation of water lock in shale gas reservoirs, so the single-well shale gas production will be increased. In conclusion, fluid occurrence and pore system in shale pores can be quantitatively divided by means of centrifugal + gradual temperature drying method combined with NMR experiments, mobile water and capillary bound water can be determined by the high speed centrifugal + NMR experiments, and capillary bound water and clay bound water can be determined by the gradual drying + NMR experiments.

There exists the Wusheng-Shizhu and Chongqing-Qijiang intra-platform depressions in the eastern Sichuan Basin during the Late Permian to the Early Triassic. The clear understanding of the sedimentary pattern and evolution of reef-shoal around the depression-margin has a practical significance for guiding the exploration and development of the Permian–Triassic reef and shoal gas fields. Based on observation, the systematic sampling and laboratory analysis of typical outcrops of the Changxing Formation (i.e. Juandong, Juhuaba, Lengshuixi, and Taiyuan) are located in the eastern Sichuan Basin. Combined with drilling data and previous studies, the study area is dominated by a ramp sedimentary environment, except for the Kaijiang-Liangping Trough in the Early Changxingian. The main sediments are micrite-containing chert nodules and micrite. With the regression that took place during the Middle-Late Changxingian, there is a distinct sedimentary differentiation that began to appear. There is a “two depressions–one platform–one trough” sedimentary pattern from south to north in the study area in the Changxingian. In essence, there exists the Chongqing-Qijiang and the Wusheng-Shizhu intra-platform depressions (two depressions), platform-flat (one platform) between the Wusheng-Shizhu intra-platform depression and the Kaijiang-Liangping Trough, and the Kaijiang-Liangping Trough (one trough). The reef-shoal of the northern depression-margin distributes between the 2nd Member and lower part of the 3rd Member. By comparison, the reef-shoal of the southern depression-margin distributes in the upper part of the 3rd Member; this indicates that the deposition of reef-shoal shows “earlier in the north and later in the south.” It is considered that the sedimentary palaeogeomorphology of the Changxingian is characterized by “higher in the north-lower in the south.” The clear understanding of the sedimentary pattern and evolution of reef-shoal around depression-margin reveal a new field for exploration and development of the Permian Changxing reef-shoal gas fields in the eastern Sichuan Basin.

Shale porosity is one of the important parameters for shale reservoir quality evaluation and shale gas reserve calculation, so it is very important to accurately measure shale porosity. There are many methods to measure shale porosity. Liquid saturation and helium saturation methods are applied to core plugs and crushed samples. At present, there are few comparative studies on the measurement results of the porosity of plug samples and crushed samples, and the differences between them are even less reported. Firstly, the porosity of plug samples is measured using different measurement methods. Then, the plug samples are crushed and the porosity of the crushed samples is measured, and the factors affecting porosity are analyzed. Finally, the differences between the porosity of the plug samples and the crushed samples are compared. The experiment results show that the porosity of shale plug samples (helium saturation method) is the connected porosity of shale, and the porosity of crushed samples is the total porosity of shale, and the latter is 0.65%-2.40% higher than the former, which accounts for 11.21%-44.36% of the total porosity. There are several reasons. (1) The injection pressure of helium saturation method is too low. (2) The samples are not evacuated. (3) A large number of unconnected pores in the shale plug samples are not effectively saturated with helium. The correlation between different mineral components and the porosity of plug and crushed samples shows that the unconnected pores mainly exist in organic matter and a small amount in clay minerals. Appropriate chemical reagents can be added in the process of reservoir transformation to effectively modify the structure of organic matter and clay minerals, and release shale gas in these disconnected pores as far as possible, so as to improve shale gas recovery.